Lawrence J. Wolfe, Patrick R. Day, and Walter F. Eggers, III of Holland & Hart, LLP; Brent R. Kunz of Hathaway & Kunz, P. C.; and Michael Murray of ExxonMobil Corporation, for ExxonMobil Corporation (ExxonMobil).

Martin L. Hardsocg and William F. Russell of the Wyoming Attorney General’s Office for the Wyoming Department of Revenue (Department).

The Wyoming State Board of Equalization (Board) shall review final decisions of the Department on application of any interested person adversely affected, including boards of county commissioners. Wyo. Stat. Ann. § 39-11-102.1(c). Taxpayers are specifically authorized to appeal final decisions of the Department. Wyo. Stat. Ann. § 39-14-209(b). The taxpayer’s appeal must be filed with the Board within thirty days of the Department’s final decision. Wyo. Stat. Ann. § 39-14-209(b); Rules, Wyoming State Board of Equalization, Chapter 2, § 5(a). By Notices of Appeal dated June 13, 2006, and October 31, 2006, ExxonMobil timely appealed two final decisions of the Department. The Board accordingly has jurisdiction to hear these matters.

A hearing was held June 4 and June 5, 2007, before the Board, consisting of Alan B. Minier, Chairman, Thomas R. Satterfield, Vice Chairman, and Thomas D. Roberts, Board Member.

This appeal concerns the valuation of 2005 natural gas production from the LaBarge Field in Sublette County processed at the Shute Creek plant owned and operated by ExxonMobil.

ExxonMobil, in the spring of 2006, filed annual gross products returns with the Department reporting its 2005 natural gas production from the Fogarty Creek, Lake Ridge and Graphite Units in the LaBarge Field located in Sublette County (LaBarge production). ExxonMobil owns and operates the Black Canyon Facility (Black Canyon) in Sublette County and the Shute Creek Gas Plant (Shute Creek) located in Lincoln County with a compressor facility in Sweetwater County. ExxonMobil reported the taxable value of 2005 LaBarge production using the proportionate profits methodology, as directed by the Department in letters sent to ExxonMobil in 2004. This was a change in methodology from the previously employed Tax Settlement Agreement (TSA) valuation method, and represented the first time proportionate profits methodology had been employed for LaBarge production. See, Exxon Mobil Corp., Docket Nos. 2004-84, et al., Dec. 1, 2005, 2005 WL 3347975 (hereinafter the 2004-84 Appeals) at ¶¶ 2-3, 15-20; see also Wyoming Dept. of Revenue v. Exxon Mobil Corp., 150 P.3d 1216 (Wyo. 2007) (describing operation of TSA methodology).

The Department did not accept ExxonMobil’s reported values for the 2005 LaBarge production. ExxonMobil’s proportionate profits methodology calculation, among other things, did not include production taxes and royalties in the direct cost ratio; placed the point of valuation upstream of Black Canyon; and included post-plant transportation costs in the denominator of the direct cost ratio. ExxonMobil also did not include the value of its federal helium sales in gross revenues. In its Notice of Valuation (NOV) issued May 16, 2006, the Department included taxes and royalties as direct costs of producing in the direct cost ratio; set the point of valuation at the outlet of Black Canyon; and deducted the respective post-plant transportation charges from gross revenues for each mineral rather than include them in the denominator of the direct cost ratio. ExxonMobil challenged this Notice pursuant to Wyo. Stat. Ann. §§ 39-14-209(b), 39-13-102(n), and Rules, Wyoming State Board of Equalization, Chapter 2, § 5(a) by an appeal docketed June 13, 2006.

The Department subsequently issued a Notice of Valuation Change (NOVC) on October 5, 2006, increasing the value of ExxonMobil’s 2005 LaBarge production. The Department calculated the NOVC in the same manner as the NOV, with one exception: in the NOVC, the Department included the value of the LaBarge federal helium sales in the assessed value for severance and ad valorem taxes. ExxonMobil challenged this increase in value by an appeal docketed October 31, 2006.

The two separate appeals of the NOV and NOVC were consolidated by Board order dated November 13, 2006. Both appeals took exception to the point of valuation used by the Department; the assessment of federal helium; and the Department’s valuation calculation using the proportionate profits method. Argument and evidence on these issues had been presented to the Board but not addressed in the 2004-84 Appeals since the Board decision in those appeals did not require the issues be resolved. In these consolidated appeals, in order to avoid duplication of extensive testimony and exhibits, the Board has accepted as evidence a substantial portion of the record presented in the 2004-84 Appeals in June, July, and September, 2005.

We affirm, for the reasons noted herein, the original Notice of Valuation as well as the Notice of Valuation Change, as corrected on limited remand to the Department with instructions to void the assessment of federal helium and correct proportionate profits methodology mathematical calculations which the Department has agreed are erroneous.

ExxonMobil, in its updated prehearing pleadings, identified six contested issues of fact and six contested issues of law pertaining to the valuation of natural gas processed at Shute Creek. ExxonMobil stated the issues of fact as:

a. What is the proper point of valuation for ExxonMobil’s production; where does the production process end?

f. Are the costs disallowed by the Department for treatment in the direct cost ratio necessary to transport the processed gas to a market?

[Petitioner ExxonMobil Corporation’s Updated Issues of Fact and Law and Exhibit Index, p. 1].

a. What is the correct point of valuation for ExxonMobil’s production under Section 39-14-203(b)(iv)?

d. Is the Black Canyon facility a “processing facility” under Section 39-14-203(b)(iv)?

e. Does the Department have authority under the proportionate profits statute to netback post-plant transportation costs from gross revenues rather than include those costs in the direct cost ratio under the proportionate profits statute?

[Petitioner ExxonMobil Corporation’s Updated Issues of Fact and Law and Exhibit Index, p. 1].

The Department, in its updated prehearing pleadings, identified two contested issues of fact and five contested issues of law:

a) Did Exxon create a “processing facility” through modifications it made to the Black Canyon Dehydration Facility?

b) Does the Black Canyon Dehydration Facility perform “processing” functions as defined in Wyo. Stat. § 39-14-201(a)(xviii)?

a) Does the Black Canyon Dehydration Facility perform “processing” functions as defined in Wyo. Stat. § 39-14-201(a)(xviii)?

b) Did the Department properly place the point of valuation, pursuant to the proportionate profits methodology, at the outlet of the Black Canyon Dehydration Facility? In other words, is the Black Canyon Dehydration Facility a “processing facility?

c) Is Exxon’s production of helium from federal lands subject to severance and ad valorem taxes?

d) Did the Department properly classify and include in the direct cost ratio post processing transportation costs?

e) Did the Department properly apply the proportionate profits method of valuation to value Exxon’s 2005 production?

[Department of Revenue’s Updated Issues of Fact and Law and Exhibit Index, pp. 3-4].

After ExxonMobil filed these consolidated appeals, the issues with regard to production taxes and royalties within the calculation of the proportionate profits valuation methodology were resolved by the Wyoming Supreme Court. RME Petroleum v. Wyoming Department of Revenue, 2007 WY 16, 150 P.3d 673 (Wyo. 2007). The Court ruled the proportionate profits methodology should not include production taxes and royalties as direct costs in the direct cost ratio.

After conclusion of the hearing for these consolidated appeals in June, 2007, the issue of assessment of federal helium for both severance and ad valorem tax was addressed by the Wyoming Supreme Court. Wyoming Department of Revenue v. ExxonMobil Corporation, 2007 WY 112, 162 P.3d 515 (Wyo. 2007). The Court stated the production by ExxonMobil of federal helium may not be assessed either severance or ad valorem tax. The Department thus concedes its assessment of federal helium for ExxonMobil’s 2005 production was erroneous. [Department of Revenue’s Proposed Findings of Fact and Conclusions of Law, p. 5].

1. ExxonMobil reported the 2005 production for the LaBarge Field, infra, ¶¶ 12-24, using the proportionate profits valuation methodology with a point of valuation upstream of Black Canyon. Infra, ¶¶ 25-32. Production year 2005 was the first year ExxonMobil calculated the value of its LaBarge production using the proportionate profits method. [Transcript Vol. I, pp. 69, 90]; Wyo. Stat. Ann. § 39-14-203(b)(vi)(D).

2. The Department issued a Notice of Valuation (NOV) on May 16, 2006, valuing the LaBarge 2005 production using 2004 production revenue and expenses as previously submitted by ExxonMobil. The NOV did not include valuation of ExxonMobil’s production of federal helium. [Transcript Vol. I, pp. 69-71; Vol. II, pp. 285-287; Exhibit 800].

3. The Department subsequently issued a Notice of Valuation Change (NOVC) on October 5, 2006, which increased the value of the 2005 LaBarge production based on a review of ExxonMobil’s 2005 production revenue and expenses as reported to the Department. [Exhibit 801]. The NOVC also included a valuation for federal helium production. [Transcript Vol. I, p. 72; Vol. II, p. 289].

4. The values established by the Department in both the NOV and the NOVC utilized the proportionate profits methodology with production taxes and royalties included as direct costs in the direct cost ratio. [Transcript Vol. I, p. 72; Vol. II, p. 289].

5. The Department, in both the NOV and the NOVC, set the point of valuation at the tailgate (outlet) of Black Canyon. ExxonMobil asserts the point of valuation should be either the custody transfer meters or the inlet of Black Canyon. The point of valuation for LaBarge production was not an issue under the 1989 Tax Settlement Agreement. [Transcript Vol. I, pp. 73-74; Vol. II, p. 287; Vol. VI, pp. 844-845, 848-849; VII, p. 993; Vol. VIII, pp. 64, 104].

6. The Department, in both the NOV and the NOVC, deducted, on a dollar-for-dollar basis, post-plant transportation expenses from the gross revenue of each mineral for which there were such expenses. ExxonMobil asserts post-plant transportation should be included in the direct cost ratio of the proportionate profits valuation methodology. [Transcript Vol. I, pp. 70, 74-75, 101; Vol. II, pp. 287, 305-319; Vol. VI, p. 839; Vol. VII, pp. 895-896, 961-962, 995; Vol. VIII, p. 105].

7. The Department acknowledged the valuation of ExxonMobil’s 2005 LaBarge production should not include production taxes and royalties as direct costs in the direct cost ratio of the proportionate profits methodology. [Transcript Vol. II, p. 287-289].

8. ExxonMobil established that the actual total tax rate applicable to its 2005 production, including severance, conservation and ad valorem taxes, was 11.9%. The Department, in deriving its NOV value used 13%, and for the NOVC value used 14%. [Transcript Vol. I, pp. 75-76]. The Department agreed the tax rate discrepancy should be corrected using ExxonMobil’s actual tax rate for 2005 production. [Transcript Vol. II, pp. 287-289, 354].

9. The Wyoming Supreme Court, on July 18, 2007, after completion of the June hearing in this matter, issued an opinion in Wyoming Dept. of Revenue and Bd. of County Comm’rs of the County of Sublette v. Exxon Mobil Corp., 2007 WY 112, 162 P.3d 515 (Wyo. 2007). The Court determined the Department could not impose severance or ad valorem taxes on the net revenues which ExxonMobil obtained from its resale of federal helium. Id. at ¶¶ 24-34. The Department filed a Motion for Reconsideration which was denied. Id. (August 21, 2007).

10. During the hearing in this matter, Tuan Pham, ExxonMobil’s former severance tax manager [who held the position in 2005], testified the same helium leases and Helium Agreement analyzed by the Wyoming Supreme Court in the Wyoming Dept. of Revenue and Bd. of County Comm’rs of the County of Sublette v. Exxon Mobil Corp. opinion were in effect in 2005. Mr. Pham also testified that none of the facts and circumstances analyzed by the Supreme Court concerning LaBarge federal helium were different in production year 2005. [Transcript Vol. I, pp. 67, 76-78].

11. Craig Grenvik, Administrator of the Mineral Tax Division, on behalf of the Department, agreed none of the facts and circumstances analyzed by the Wyoming Supreme Court concerning LaBarge federal helium were any different in production year 2005. [Department of Revenue’s Proposed Findings of Fact and Conclusions of Law, p. 5]. The Department acknowledged its assessment of federal helium was incorrect, and federal helium sales revenues should be removed from the valuation of 2005 LaBarge production. [Transcript Vol. II, pp. 284-285.

12. ExxonMobil operates three federal natural gas units located in the LaBarge Field in the Bridger-Teton National Forest in Sublette County, Wyoming. The three units are known as Fogarty Creek, Lake Ridge and Graphite. [Joint Stipulation of Facts, ¶ 1; Transcript Vol. III, p. 94; Exhibit 106 p. 15895; Exhibit 146, pp. 16408-16413; and Exhibits 171, 175, 177, 178, 179].

13. Mobil drilled the first well into the Madison Formation, the source of LaBarge gas, in 1963. Exxon drilled its first well in 1969. The existing well fields were perforated at a depth of 15,500 to 16,000 feet below the wellheads. [Transcript Vol. III, pp. 99-100; Exhibit 106, pp. 15908, 15914-15915; Joint Stipulation of Facts, ¶ 2].

14. ExxonMobil estimates there are 167 trillion cubic feet of natural gas in place in the reserve. Based on a processing capacity of 720 million standard cubic feet a day, which is the current design capacity for both Black Canyon and Shute Creek, the LaBarge project could produce gas for another two hundred years. [Transcript Vol. I, p. 167; Vol. III, p. 65; Joint Stipulation of Facts, ¶ 5].

15. The LaBarge gas reserve is a multi-component gas consisting primarily of carbon dioxide [CO₂] but also containing other valuable components, including methane and helium. The reserve is considered to be “sour gas” as it contains hydrogen sulfide [H₂S]. The general composition of the gas reserve is:

Carbon dioxide	65%
Methane	22%
Nitrogen	7.4%
Hydrogen sulfide	5%
Helium	.6%

[Transcript Vol. III, pp. 101-102; Exhibit 106, p. 15910; Joint Stipulation of Facts, ¶ 3].

16. There are no natural gas liquids in the LaBarge gas. [Transcript Vol. III, p. 102; Vol. IV, pp. 238-246; Exhibit 133, p. 13458].

17. The LaBarge gas, unlike most natural gas in Wyoming, is not flammable before processing. It is a unique gas stream, and may in fact be the lowest BTU gas produced in the world. The gas stream is lethal due to its high concentration (50,000 parts per million) of hydrogen sulfide. A concentration of 700 parts per million of H₂S in a gas stream can be fatal. In addition, when in contact with water, both H₂S and CO₂ form corrosive acids which can destroy a carbon steel pipeline. In the view of the Department, because of the concentration of carbon dioxide, no other natural gas stream in Wyoming is “remotely similar.” [Joint Stipulation of Facts, ¶ 4; Transcript Vol. III, p. 103; Vol. IV, pp. 360-361; Vol. V, pp. 511-513, 537-539; Exhibit 152, pp. 13563-13564].

18. ExxonMobil produces the LaBarge sour gas from 18 wells. [Transcript Vol. III, pp. 66, 97; Exhibit 106, pp. 15898-99, 15924]. Each well site has a “well building.” Each building contains equipment to assist in production and movement of gas from the wellhead downstream. There are also meters to measure the gas volumes. [Transcript Vol. III, pp. 66-67, 110, 115; Exhibit 106, pp. 15924-15926, 15930-15931; Exhibit 161]. The gas production from each well can be shut down or the rate of production controlled remotely from Black Canyon or manually at each wellhead site. It is common for gas plants to include controls to remotely operate the gas wells. [Transcript Vol. I, pp. 161-162, 164, 169; Vol. II, p. 231; Vol. III, pp. 112, 173-174; Vol. V, p. 498].

19. ExxonMobil injects corrosion inhibitors into the raw gas stream at the wellhead to protect the flowlines as well as the downstream pipelines and facilities. H₂S and CO₂ are extremely corrosive in the presence of water which condenses out of the gas on the way up the well bore. Infra, ¶ 21. ExxonMobil also injects methanol which is a hydrate inhibitor. Both the corrosion inhibitors and methanol are delivered by pipeline from Black Canyon. [Transcript Vol. III, pp. 67-68, 77, 118; Vol. IV, pp. 361, 369; Exhibit 106, pp. 15924, 15933]. The wellhead facilities are not manned 24 hours a day, however they are accessible. The operations at the well sites are automated and remotely controlled. [Transcript Vol. III, p. 69].

20. The LaBarge sour gas travels approximately one to two miles from most well sites to a manifold site. There are three manifolds, each of which serves approximately 5 wells. From two of the manifolds, numbers 3 and 9, gas flows into the third manifold, number 15. Two of the 18 wells, FC 16-32 and GU 2-15, do not flow through a manifold. Gas from FC 16-32, if producing, feeds directly into Black Canyon. Well GU 2-15 is plugged and abandoned. [Transcript Vol. I, p. 121; Vol. III, pp. 66, 71-73, 83, 119-120, 107-109, 170; Vol. V, pp. 474-475; Exhibit 106, pp. 15916, 15924, 15938-15941, 15943-15944, 15950].

21. The LaBarge gathering and separating system removes 95% of the water found in the raw gas stream. The gas composition in the well bore contains 3.7% water. The pressure of the gas drops from 5000 psi to 1400 psi; it cools from 270-280°F to 120-140°F; and the velocity increases from 100 mph to 300 mph as the gas rises three miles to the wellhead. Some of the water in the gas condenses on the way up the well bore, thus the gas includes a fine water mist when it reaches the wellhead, as well as water in a gaseous phase. The gathering system takes the misted gas stream to the manifolds. [Joint Stipulation of Facts, ¶ 10].

22. Free water accumulates as the gas stream travels from the wellheads, and is separated in the manifolds by large cylindrical vessels. Each cylinder vessel is “a wide spot in the line” where the gas flow rate is reduced to allow water droplets to fall out. [Transcript Vol. III, pp. 73-74, 76-77; Exhibit 106, pp. 15948-15952]. After this separation activity, the remaining gas contains 0.22% water. The condensed water falling out at the manifolds contains hydrogen sulfide, and is thus piped downstream in separate flowlines to Black Canyon where it is injected into disposal wells. [Transcript Vol. I, p. 143; Vol. III, pp. 75, 84-85, 124; Exhibit 106, p. 15944; Joint Stipulation of Facts, ¶¶ 10, 11].

23. ExxonMobil considered the raw gas stream ready for processing at the outlet of the three manifolds located near Black Canyon. The United States Bureau of Land Management [BLM] nonetheless prepared a full environmental impact statement, and dictated the main gas processing facilities be located at Shute Creek, approximately forty miles south of the well field manifolds. This final environmental decision was dated January 25, 1984. [Transcript Vol. III, p. 146; Vol. V, pp. 637-638; Joint Stipulation of Facts, ¶ 7]. Had the Shute Creek plant been located at or near the well field, the raw gas stream could have been delivered directly into the sweetening process after the separation of liquid water in the manifolds. [Transcript Vol. IV, p. 346; Vol. V, pp. 516-519, 603-609; Exhibit 144].

24. ExxonMobil, before constructing Black Canyon, contemplated constructing multiple field dehydrators in order to prepare the LaBarge sour gas stream for movement to Shute Creek. [Transcript Vol. V, pp. 476-478; Exhibit 107, pp. 15543-15547].

25. The original purpose for construction and operation of Black Canyon was to dehydrate the LaBarge raw sour gas to ensure it could be safely transported in a pipeline 40 miles to Shute Creek in Lincoln County. Dehydration prevents the formation of corrosive acids and as well as the formation of hydrates which could plug the pipeline. Sour gas can form hydrate solids at temperatures around 60º F. [Transcript Vol. IV pp. 264-265, 274-275, 360-361, 365; Vol. V pp. 606-607; Exhibit 152, pp. 13563-13564].

26. ExxonMobil identified only two domestic facilities, and five facilities in the entire world which dehydrate gas as sour as the LaBarge production. According to Steve MacFarland, a process engineer testifying on behalf of ExxonMobil, Black Canyon is the only facility in Wyoming which dehydrates sour gas through the triethylene glycol [TEG] process. [Transcript Vol. I, pp. 179-180; Vol. IV, pp. 271, 363,].

27. Black Canyon required a capital investment of $134 million (in 1984 dollars) to construct in the mid-1980's. [Joint Stipulation of Facts, ¶ 30].

28. Air quality considerations prohibit ExxonMobil from emitting any H₂S (or burning the H₂S which would create sulfur dioxide, SO₂) at Black Canyon. ExxonMobil must therefore recycle and recover 100% of any contaminants removed from the raw gas stream. ExxonMobil built Black Canyon for “zero emissions,” necessitating capital investment to compress and recycle all gas extracted by the TEG regenerator, to handle acidic water re-injection, and to undertake other activities which are not associated with typical well-site dehydrators. [Transcript Vol. I, pp. 126-127; Vol. IV, pp. 244; 309].

29. Black Canyon is a 24-hour manned facility located approximately three miles downstream of the manifolds. It is approximately 1500 feet by 1500 feet in size, with office space for more than 30 full-time employees, a warehouse, a maintenance garage, and two separate processing train buildings. It also has a control system for field operations as well as facilities for repair and maintenance of equipment. [Transcript Vol. III, pp. 77-83; Vol. IV, pp. 348-351, 376; Exhibit 106, p. 15975; Exhibit 128]. Black Canyon is the first point at which all LaBarge gas production is commingled. [Transcript Vol. I, pp. 157-58; Vol. III, p. 170; Vol. V, pp. 474-475; Exhibit 106, p. 15972].

30. The purpose of Black Canyon is consistent with the general purpose for dehydrating natural gas. Dehydration prevents corrosion which occurs when water mixes with the acid components of the raw gas stream, and also prevents the formation of hydrates. Black Canyon dehydrates the raw gas stream for safe transportation through approximately 40 miles of “trunk line” to Shute Creek. [Joint Stipulation of Facts, ¶ 7; Transcript Vol. II, pp. 212-213, 216; Vol. IV, pp. 264-265, 274, 365; Vol. V, pp. 432-433, 603-604, 643-645; Exhibit 133, p. 13457; Exhibit 132, p. 15852].

31. The dehydration of sour gas is inherently challenging and complex since the “sour water” removed from the gas must be disposed of safely. Dehydrating gas with lethal quantities of H₂S requires additional precautions and equipment as compared to the dehydration of sweet gas. [Transcript Vol. IV, p. 371; Vol. VI, pp. 718-721].

32. Dehydration of sour gas normally occurs after the gas is sweetened. [Transcript Vol. IV, p. 270, Vol. V, pp. 449-450]. Environmental constraints obliged ExxonMobil to locate its processing facility at Shute Creek, approximately forty-three (43) miles downstream from the production manifolds. [Transcript Vol. V, pp. 516-518]. ExxonMobil argues an independent dehydration facility at Black Canyon was unnecessary but for the environmental constraints. [Transcript Vol. II, pp. 218-219; Exhibit 104, p. 17052].

33. Production from the LaBarge wells, when it arrives at Black Canyon, is split into two processing trains, each of which uses TEG to dehydrate the raw gas stream. [Transcript Vol. III, pp. 82, 129; Vol. IV, p. 284; Exhibit 106, p. 15973]. Black Canyon employs “slug catchers” to remove “slugs” of liquid water which accumulate as the raw gas moves through the pipelines from the manifolds. [Transcript Vol. I, pp. 121-122 Vol. III, p. 84].

34. The raw gas stream first enters a scrubber at Black Canyon in which free water drops out. The gas then enters a dehydration absorber tower, in which the gas rises and lean [clean] TEG rains down through trays inside the absorber tower. The TEG uses the process of “absorption” (one component dissolves into, and becomes a part of another component) to absorb water from the gas which is then considered “dry” and passes out the top of the tower. After removing the water vapor from the gas, the TEG is boiled to vaporize the captured water out of the TEG. The lean TEG is then recycled and again applied to the gas stream. TEG at times may overflow the absorber tower, and pass downstream in the 40-mile trunk line to Shute Creek. [Transcript Vol. I, p. 122; Vol. III, pp. 128-130, 134-135; Vol. IV, pp. 329, 414; Vol. V, pp. 562-563, 590-591; Exhibit 106, pp. 15973, 15983; Exhibit 151, pp. 13414-13416].

35. Water removed from the TEG contains hydrogen sulfide, methane, carbon dioxide, and all other constituents of the raw gas. The water is considered acidic, and is injected into disposal wells located at Black Canyon. [Transcript Vol. III, pp. 134-135; 141-142; Vol. V, pp. 580-581; Exhibit 106, pp. 15983, 15985-15992, 16004-16005].

36. According to Steve MacFarland, it is common for a single solvent, such as TEG, to remove multiple components from a raw gas stream. Dr. Robert Enick, head of the chemical engineering department at the University of Pittsburgh, also testifying on behalf of ExxonMobil, stated that every single component in a raw gas stream is dissolved to some extent in the TEG. The TEG process at Black Canyon, on an annual basis, in addition to removing water vapor, thus separates about 5,000 tons of H₂S and about 17,000 tons of CO₂ from the raw gas stream. Dr. Enick indicated this is a very small amount, only about one percent (1%), of the total quantity of H₂S and CO₂ entrained in the raw gas stream. MacFarland estimated only approximately nine (9) tons of the total H₂S removed and approximately two (2) tons of the total CO₂ removed are entrained in the acidic water which is injected at Black Canyon. [Transcript Vol. I, pp. 123-124, 130, 170, 173-174; Vol. II, pp. 191, 200-204, 253-256, 264; Vol. V, pp. 567-573, 580-581; Exhibit 183].

37. Black Canyon is designed to process as much as 720 million standard cubic feet of raw gas per day between its two processing trains. Each processing train removes approximately 125,000 cubic feet of H₂S per day from the raw gas stream. Almost 100% of this H₂S is reinjected back into the raw gas stream after dehydration and ultimately removed at Shute Creek. [Transcript Vol. I, pp. 124-125; 167-168; Vol. II, pp. 201-206; Exhibit 183].

38. The H₂S and CO₂ removed from the rich [dirty] TEG is recovered through compression. Four 300-horsepower four-stage compressors take the relatively low pressure H₂S and CO₂, compress both gases up to the inlet pressure of the facility, approximately 1,300 pounds, and then inject both back into the raw, now dehydrated, gas stream headed for Shute Creek. This process prevents any of the H₂S and CO₂ from escaping into the atmosphere at Black Canyon. This recycled gas ends up at Shute Creek where the H₂S and CO₂ are permanently removed. ExxonMobil asserts it is the necessity of locating Shute Creek at its present location rather than where Black Canyon is located which requires H₂S to be removed twice from the raw gas stream. [Transcript Vol. I, pp. 126-127, 142, 168, 171; Vol. IV, pp. 371-372; Exhibit 129, pp. 16258, 16259, 16262].

39. The H₂S which is removed at Shute Creek is now injected into the Madison Formation Reservoir. [Transcript Vol. I, p. 127].

40. It is not unusual to find contaminants in natural gas. All natural gas will contain any number of naturally occurring contaminants or unwanted components. [Transcript Vol. III, p. 179; Vol. IV, p. 416; Vol. V, pp. 541-542]. ExxonMobil originally had no idea of the scope of the naturally occurring contaminants in the raw gas stream. [Transcript Vol. V, pp. 433-434]. It subsequently identified a number of unexpected naturally occurring contaminants in the LaBarge gas stream in the early to mid-1990's. [Transcript Vol. V, pp. 439-440].

41. Among the contaminants identified in the LaBarge raw gas stream were “heavy hydrocarbons” (HHCs), a general term for heavier trace contaminants found in that production. These contaminants included a particularly prominent type of HHC called dibenzothiophene (DBT). MacFarland had never heard of DBTs occurring anyplace except in the raw gas from the LaBarge field. Dr. Enick reached the same conclusion. [Transcript Vol. III, pp. 190-91; Vol. IV, pp. 279-280; Vol. V, p. 441; Vol. VI, pp. 690-691; Exhibit 106, p. 15910; Exhibit 132, p. 15855].

42. Dibenzothiophenes (DBTs), other heavy hydrocarbons (HHCs) and elemental sulfur have always been present in very minuscule amounts in the raw gas stream entering Black Canyon. The DBTs amount to .6 parts per million of the raw gas stream, and the other combined HHCs consist of another .5 parts per million. The elemental sulfur produced in the raw gas stream was present in concentrations of 6.4 parts per million. These small concentrations on a parts per million basis were not initially recognized as being present in the raw gas stream. Such small concentrations escape the detection limits of most measurement technologies. In addition, the compounds can settle out as solid deposits in gas sample containers, preventing their detection by a gas chromatograph. [Transcript Vol. I, pp. 133-134; Vol. IV, p. 281; Vol. V, pp. 551-556; Exhibit 151, pp. 13344-13346, 13350].

43. The DBTs and other HHCs produced in the raw gas stream at LaBarge leave the well bore in the gaseous phase. The LaBarge gas contains no liquid heavy hydrocarbons. Supra, ¶ 16. Ordinarily, DBTs and other HHCs, if produced, would be dissolved in produced liquid hydrocarbons and separated from the raw gas stream in the processing steps used to remove liquid hydrocarbons from the gaseous hydrocarbons. Because LaBarge produces no liquid hydrocarbons, these heavy hydrocarbons are produced in the gas phase and are separated out of the raw gas stream at Black Canyon. [Transcript Vol. IV, p. 295; Vol. V, pp. 541-544; 555-556].

44. When ExxonMobil initiated LaBarge production through Black Canyon, it discovered very small quantities of HHCs, including DBTs, were being adsorbed by the TEG. The TEG dehydration process will capture very small amounts of all unwanted gas components. [Transcript Vol. II, p. 191; Vol. III, p. 181; Vol. V, p. 448; Vol. IV, p. 309]. These contaminants turned the TEG black. [Transcript Vol. IV, pp. 211-215, 217-218, 222, 228-229, 237, 265, 419-420; Exhibit 106, p. 15910; Exhibit 132, p. 15855]. Such contaminants are typically contained within natural gas liquids in the gas stream and are not a significant problem. As previously noted, the LaBarge production contains no appreciable natural gas liquids or condensate. [Transcript Vol. IV, pp. 237-239; Vol. V, pp. 481-482, 542-543; Vol. VI, p. 699].

45. Steve MacFarland concluded, based upon the detection capability of his testing equipment, the presence of DBTs and other HHCs in the TEG solution did not affect the ability of the TEG to dehydrate the raw gas stream. The DBTs, other HHCs, and elemental sulfur were, however, settling out of the raw gas stream and contaminating and fouling equipment at Black Canyon, the pipeline to Shute Creek, and then the processing equipment at Shute Creek as well. ExxonMobil initially removed these materials from the equipment by hand during alternate, periodic shut downs of each processing train at Black Canyon. MacFarland stated removal of the contaminants from the equipment was required, otherwise the entire operation from Black Canyon through Shute Creek would eventually fail. [Transcript Vol. I, pp. 128-130; Vol. IV, pp. 240-241, 284-285, 291-292, 295, 297-298, 303, 306-307, 318-319, 323, 329, 425; Vol. V, pp. 575-577; 590-591; Vol. VI, pp. 712-713; Exhibit 132, pp. 15859, 15875; Exhibit 151, pp. 13414-13416].

46. ExxonMobil was required to dispose of the DBTs and other HHCs absorbed by the TEG solution by hazmat procedures in a controlled environment. The absorption of the DBTs and other HHCs would foul the TEG solution, and cause the TEG absorber column to become unstable. ExxonMobil cleaned the TEG solution of the DBTs and other HHCs through adsorption (a component is dissolved into another however the molecules are merely attracted to and stick to the surface of other molecules) using a carbon filter. The DBTs and other HHCs can not be boiled out of the TEG since they are much less volatile and thus have a higher boiling point temperature than the boiling point temperature for TEG. [Transcript Vol. II, pp. 329-330; Vol. IV, pp. 220-222, 253-254; 284-285, 291-292, 295, 297-298, 303, 306-307, 318-319, 329; Vol. V, pp. 575-577, 582, 588-591, 596; Vol. VI, pp. 733-734; Exhibit 132, pp. 15859, 15875; Exhibit 151, pp. 13414-13416].

47. Black Canyon originally used two activated carbon filters to remove any materials which might degrade the TEG. [Transcript Vol. III, p. 138; Exhibit 106, p. 15991; Exhibit 144]. Dehydrators commonly filter TEG, however the size of filtration systems varies. [Transcript Vol. III, pp. 182-183].

48. Each original TEG dehydration system at Black Canyon included a carbon filter, containing 1,000 pounds of carbon particles, designed to clean the TEG solution through the process of adsorption. Carbon is a commonly used material in such filters. [Transcript Vol. VI, pp. 675-677]. The filter was designed for only the contaminants which had been introduced into the raw gas stream, not those contaminants naturally existing in the gas stream, such as DBTs and other HHCs. ExxonMobil did not anticipate the original carbon filters would capture the other naturally occurring contaminants. The original 1,000 pound carbon particle filters did in fact adsorb the naturally occurring gas contaminants present in the TEG solution, but could not adsorb the quantity of those contaminants collected by the TEG solution. [Transcript Vol. IV, pp. 225-226, 415-418, 420; Vol. V, pp. 584-587, 592; Exhibit 133, p. 13465].

49. A larger activated carbon filtration system was installed in 2003 to reduce downtime associated with the periodic cleanup of contamination in the systems, supra, ¶ 45,and to allow the dehydration system at Black Canyon to work more effectively. [Transcript Vol. III, pp. 184-85]. As with the original filter, the newly designed, larger filter used adsorption to remove the DBTs and other HHCs from the TEG solution. [Transcript Vol. I, pp. 143-144; Vol. III, pp. 138-139, 184-185; Vol. IV, pp. 225-226, 422; Vol. V, p. 481; Vol. VI, pp. 684-687; Exhibit 106, p. 15993].

50. The larger filtration system employed two tanks, each holding 10,000 pounds of activated carbon, a very fine charcoal-like material. As a result of their shape, the active carbon particles have a large surface area. The DBTs and other HHCs are captured by adsorption on this surface area. [Transcript Vol. I, pp. 136, 144; Vol. III, p. 132; Vol. V, pp. 590-596; Vol. VI, p. 735]. The activated carbon is replaced every two weeks. A contractor recycles the carbon by heating it to a point which removes the DBTs and other HHCs. [Transcript Vol. IV, pp. 231-232, 333, 342]. The larger filters more effectively removed the contaminants from the TEG solution. [Transcript Vol. IV, pp. 323-324; Exhibit 132, p. 15875].

51. Grenvik agreed the TEG dehydration process at Black Canyon permanently removes DBTs and other HHCs from the raw gas stream. [Transcript Vol. II, p. 334].

52. DBTs and other HHCs can be marketed and sold only in small quantities. They are generally sold by the gram to chemists for use in experiments. In this case, it was not economical for ExxonMobil to remove the DBTs and other HHCs from the activated carbon. These contaminants which were permanently removed from the raw gas stream were thus not separately marketed. [Transcript Vol. I, pp. 139-140].

53. Ordinarily, raw sour gas streams are not dehydrated prior to processing since the liquid solvent [Selexol] processes used to remove H₂S are “wet” processes which humidify the gas and thus require water. The TEG dehydration at Black Canyon removes less water from the raw gas stream (2376 lb/hr) than is added back into the gas stream (3204 lb/hr) at Shute Creek in the H₂S removal process. This means that even if no TEG dehydration occurred at Black Canyon, ExxonMobil would still be required to add “make-up”water at the rate of 828 lb/hr before the raw gas could be processed at Shute Creek. [Transcript Vol. II, pp. 219-220, 271; Vol. III, pp. 187-188; Vol. IV, pp. 271-272; Vol. V, pp. 516-517, 519; Exhibit 152, pp. 13567-13568].

54. Dr. Enick prepared and presented a written report on behalf of ExxonMobil. He stated the report was intended to do three things: first, to provide a brief and concise history of sweet and sour gas dehydration with TEG; second, to give a current assessment of where TEG dehydrators are used, and how many there are; and third, to revisit the question of whether Black Canyon was, from a technical point of view, a gas processing facility. Dr. Enick testified that, in preparing his report, he reviewed all available chemical engineering and petroleum engineering literature. He obtained two CDs of the complete proceedings since 1958 of the Laurance Reid Gas Conferences. He also reviewed textbooks from several universities, as well as some publicly accessible websites. Dr. Enick did not review the Wyoming statutes. He was asked to provide a purely technical point of view. [Transcript Vol. I, pp. 173-174; Vol. II, pp. 208-209, 211; Vol. V, pp. 527, 597-598, 625-626; Exhibit 151].

55. Dr. Enick set out the common attributes of processing facilities around the world. From his literature review, he ultimately concluded that from a technical, scientific, and engineering point of view, Black Canyon is a processing facility. He concluded there are two universal characteristics of a processing facility: 1) a processing facility must occur after all gathering is complete; and 2) a processing facility must remove at least one component of the gas stream. Black Canyon, according to Dr. Enick, removes at least four components - water, DBTs, other HHCs, and elemental sulfur. It was his opinion Black Canyon satisfied both criteria, and therefore was, from a technical, scientific, and engineering point of view, a processing facility from its inception. [Transcript Vol. I, pp. 155, 173-175; Vol. II, pp. 206, 221-223, 249; Vol. IV, pp. 266, 395; Vol. V, pp. 527-536, 597-602, 641-642; Vol. VI, pp. 650-652; Exhibit 151, pp. 13361-13363].

56. Steve MacFarland testified to the same opinion. He asserted that a facility which gathers all the sour gas, does all the front end operations which are consistent with a plant, then dehydrates sour gas in a zero emissions environment, disposes of all the byproducts, and sends the dehydrated gas on for additional processing, is, from a process engineering point of view, a processing facility. MacFarland’s testimony was, however, also limited to engineering parameters, definitions, and concepts. [Transcript Vol. I, pp. 155, 173-175; Vol. II, pp. 206, 221-223, 249; Vol. IV, pp. 266-267, 395; Vol. V, pp. 527-536, 597-602, 641-642; Vol. VI, pp. 650-652; Exhibit 151, pp. 13361-13363].

57. Dr. Enick also stated that, in a technical sense, Black Canyon removes DBTs and other HHCs from the methane in the raw gas stream. [Transcript Vol. II, p. 207].

58. According to Dr. Enick, there are approximately 40,000 TEG dehydrators in the United States, which he divided into three groups. Group 1 dehydrators are generally small and unattended, prepackaged or skid mounted, and mobile. They are generally located at or near the wellhead, or service a small group of three or four wells, and process gas with no more than 1000 parts per million of H₂S. There are roughly 39,000 Group 1 dehydrators in the United States. Group 2 dehydrators are much larger in capacity, more complex with far more instrumentation, are attended, and typically are permanent fixtures oftentimes within a building as a part of a gas processing facility. Group 2 dehydrators are used after production from all of the wells has been gathered together in one place, generally in a processing facility which includes a TEG process. Group 3 dehydrators are very rare. They are unusual types of TEG dehydrators used with enormous levels of H₂S, hundreds of times larger than typically associated with a Group 2 dehydrator. Enick stated that to his knowledge there are only five Group 3 dehydrators in the world, including Black Canyon. He also stated the function of every dehydrator is to remove water from the natural gas. [Transcript Vol. I, pp. 175-180, 182-183; Vol. II, pp. 189-190, 213, 216-217, 250-252; Exhibit 104, pp. 17038, 17048-17057].

59. In Wyoming, there are no other facilities which dehydrate highly sour raw gas. At the other facilities in Wyoming where raw sour natural gas is processed, the raw gas stream is delivered directly from the wells into a processing facility, without an intervening TEG process. [Transcript Vol. IV, pp. 385-386; Vol. VII, pp. 990-991].

60. Group 1 field dehydrators do not require flashing, recycle compressions or carbon adsorption beds. These dehydrators are simple, located at the well, typically operate unmanned, and vent to the atmosphere any trace amounts of contaminants along with water vapor. [Transcript Vol. I, pp. 175-177; Exhibit 104, pp. 17048-17049].

61. Dr. Enick testified that large and unique processes and equipment are necessary to handle the dehydration of large volumes of very sour gas. The various equipment and operations which are necessary based on the presence in the LaBarge gas of high concentrations of CO₂and H₂S are: TEG dehydration column, trunk line to Shute Creek, heat exchanger, flash tank, TEG regenerator, four-stage recycle compression, and cooling. [Transcript Vol. II, pp. 193-199; Exhibit 104, p. 17070].

62. The dehydration of sour gas requires different processes than the dehydration of sweet gas. Sweet gas (containing little or no hydrogen sulfide) is not toxic. The water removed from sweet gas can be vented directly into the atmosphere. Sweet gas from a well can be used to provide energy for a TEG dehydrator at or near a well, because the combustion by-products of sweet gas fuels can also be vented into the atmosphere. It is therefore relatively cheap and easy to install field dehydrators at individual well sites for sweet gas, and there are many such field dehydrators at or near wells in Wyoming. These small facilities are not significantly larger than a truck and do not have to be staffed. Steve MacFarland testified that these well-site, unmanned TEG dehydrators are commonly used throughout Wyoming. [Transcript Vol. I, pp. 176-179; Vol. IV, pp. 353-359; Exhibit 129, pp. 16250, 16251].

63. Small field dehydrators can dehydrate gas containing a small amount of H₂S, i.e., tens of parts per million. Dr. Enick, in his literature review, did not find any example in which the small Group 1 field dehydrators processed above 1000 parts per million of H₂S. The level of H₂S in the LaBarge gas is five percent by volume, or 50,000 parts per million. [Transcript Vol. II, p. 192; Exhibit 104, pp. 17038, 17048].

64. Sour gas cannot be used to fuel the TEG process at Black Canyon since the combustion byproducts of sour gas include sulfur dioxide, which is also toxic. In addition, Black Canyon is permitted as a “zero emissions” plant. Supra, ¶ 28. As a result, an additional fuel source must be employed to operate sour gas dehydration equipment. The LaBarge sour gas is also not flammable. [Transcript Vol. IV, pp. 358-360].

65. The water which is absorbed from the sour gas into the TEG still contains significant amounts of entrained sour gas. This sour gas contained in the water, and therefore in the TEG solution, must be removed from the TEG by a flashing process. In addition, sour gas is vented from the TEG during the TEG regenerating [cleaning] process when the water is boiled out of the TEG. The sour gas thus removed is highly toxic and cannot be emitted into the atmosphere. It is captured, recompressed, and reinserted into the gas pipelines which flow to the main processing facility, where it can be safely processed. Sour gas dehydration therefore necessarily requires flashing, multi-stage compression, and sour water re-injection because of the toxic nature of the gas being dehydrated. All of these processes must be conducted in a closed system with no emissions into the atmosphere, because the gas is toxic. Supra, ¶ 28; [Transcript Vol. II, pp. 192-199; Exhibit 151, p. 13365; Exhibit 104, p. 17070].

66. Flashing, multi-stage recompression, and sour water reinjection are processes associated with sour gas dehydration which do not occur in sweet gas dehydration. As a result of these additional multiple steps, and because of the need to provide external fuel supplies and to constantly staff the operation, sour gas dehydration generally cannot economically occur at or near the well head. The only economically sensible approach is to collect all gas from the multiple sour gas wells and dehydrate it at a single central facility which can handle the additional steps needed to dehydrate sour gas as well as the acidic water and sour gas byproducts with constant staff attention. [Transcript Vol. IV, pp. 364-365].

67. Dr. Enick, in his written report and his testimony, recognized that one function of Black Canyon is interim dehydration of sour gas for transportation to Shute Creek. He also noted ExxonMobil has used Black Canyon to remove several natural gas impurities capable of forming solid deposits within equipment. Dr. Enick stated in his report: “It is entirely appropriate to designate the Black Canyon facility as a gas processing facility (GPF), based on a comparison of the processes occurring at Black Canyon and the definitions and descriptions of GPFs found in the engineering literature…the Black Canyon Facility is wholly consistent with the technical descriptions and requirements for a GPF.” He testified that “the function of the dehydration processes at Black Canyon, is to remove the water for transportation.” [Transcript Vol. II, p. 212, Lines 17-19, pp. 241-242; Exhibit 104, p. 17067].

68. From a technical standpoint, Dr. Enick found the following attributes of Black Canyon most significant to his conclusion that it is a processing facility. Black Canyon (BC):

∙ does not contain near-wellhead equipment such as phase separation vessels and small wellhead TEG dehydrators.

∙ does not include any part of a gathering system, even if that gathering system contains field processing units.

∙ begins immediately after gas gathering ends, specifically at the end of the pipeline that carries the gathered gas to BC.

∙ begins at the latest place where a well in the field can be introduced to the piping network and still be completely processed. This occurs at the inlet slug catcher, where such accommodations were planned for the introduction of two individual wells to the BC facility, FC 16-32 and GU 2-15.

∙ begins where the centralized, shared, or common equipment begins, which corresponds to the inlet slug catchers and filters.

∙ [removes] liquids (water and oil) from the gas stream in slug catchers or multiple phase separation units designed to handle combined streams from gathering systems.

∙ contains one or more processes that produce a desirable change in the combined gas stream from the gathering system.

∙ has the equipment that is used to make a gathered natural gas acceptable for transportation to Shute Creek.

∙ does not contain the equipment associated with the recovery of NGL because there is not a significant amount of NGL in the natural gas. It is not, however, required that a GPF contain such processes.

∙ the raw gas stream fed into the Black Canyon Facility contains gaseous water and gaseous impurities, and the processes at Black Canyon used to remove these components include dehydration (water removal) and absorption and adsorption (removal of dibenzothiophene (DBT), heavy hydrocarbons (HHC) and elemental sulfur (S)).

∙ has the equipment that removes several components from the combined natural gas: water, DBT, HHC and S.

∙ contains an amount of equipment that is more than adequate to be classified as a [Gas Processing Facility].

69. Dr. Enick asserted in his testimony that had Shute Creek been located where Black Canyon was built, the raw gas would have entered Shute Creek without dehydration, and the Selexol sweetening process would have accumulated DBTs and other HHCs the same as occurred with the TEG process at Black Canyon. ExxonMobil would have faced the same regeneration problems with the Selexol as with the TEG, and very likely would have used a carbon adsorption unit to remove the DBTs and other HHCs from the Selexol. [Transcript Vol. II, p. 276; Vol. V, pp. 565-566; Vol. VI, pp. 712-713].

70. Dr. Enick, when reviewing Wyo. Stat. Ann. § 39-14-201(a)(xviii) during the hearing, stated that of the processes listed in the Wyoming statutory definition of “processing,” absorption, adsorption, flashing, dehydration, beneficiation, stabilizing, compression, all occur at Black Canyon. [Transcript Vol. II, pp. 278-280].

71. While the Department would agree adsorption and absorption are processes, it argues such processes do not necessarily constitute “processing.” [Transcript Vol. VII, p. 890].

72. Steve MacFarland stated his opinion that any type of dehydration is a “process” and because Black Canyon is a “facility” in which dehydration occurs, it is a “processing facility.” [Transcript Vol. I, p. 145; Vol. IV, p. 398; Vol. V, p. 442]. Dr. Enick stated his opinion that any dehydration, whether of sweet or sour gas, occurring after gathering, would occur within what he considered a processing facility. [Transcript Vol. V, p. 636].

73. The Department asserts the simple fact that TEG dehydration removes at least a small amount of almost every component in a raw gas stream does not make the dehydration facility a processing facility. [Transcript Vol. II, p. 303].

74. The Department maintains in order to have a processing facility, something more than dehydration must occur. A processing facility must produce a saleable product. [Transcript Vol. II, pp. 304-305, 324-326, 336, 338-339, 360-362; Vol. VII, p. 886, 939-940, 982, 991].

75. Grenvik testified the Department does not have a specific test which it employs to define the statutory phrase “gas processing facility.” The Department, in considering what constitutes a “gas processing facility,” relies on the Wyoming statutes and the Wyoming Supreme Court decision, Williams Production RMT Company v. Department of Revenue, 2005 WY 28, 107 P.3d 179 (Wyo. 2005). [Transcript Vol. II, pp. 322-323, 338-339].

76. Dr. Enick stated his review of the technical literature indicated that a facility does not need to produce a saleable product in order to be considered a gas processing facility. [Transcript Vol. II, p. 269].

77. The Department asserts that improving the carbon filtration system at Black Canyon, and thus making it an extraordinarily high capacity dehydrator, does not transform Black Canyon into a gas processing facility. Black Canyon, in the opinion of the Department, has been a dehydrator since the day it began operation. The fact the improved carbon filtration system keeps Black Canyon operational and may have corrected downstream fouling is a result of the Black Canyon dehydrating process not working properly prior to the improvement. [Transcript Vol. VII, pp. 887-888, 955-956, 974].

78. The Department does not distinguish, for tax purposes, between dehydration of sour gas and dehydration of sweet gas. The Department contends there is no such distinction in the Wyoming statutes. [Transcript Vol. VII, pp. 902, 941-945].

79. The Department further asserts neither the complexity nor the size of a dehydrator is a factor to consider when designating a gas processing facility for tax purposes. [Transcript Vol. II, p. 294; Vol. VI, pp. 871-872; Vol. VII, pp. 956-957].

80. Grenvik testified that when the Department makes a determination of the purpose of a facility, it looks beyond the characterization which the company may use for the facility. If, for example, a company characterizes a facility as a dehydrator and the Department determines it is, in fact, a processing facility, the Department will treat it as a processing facility, taking into account what functions it performs, not what is it called or labeled. [Transcript Vol. II, pp. 359-360].

81. The Department does not believe the environmental requirements which mandated the separate locations of Shute Creek and Black Canyon should be considered in classifying Black Canyon for tax purposes. [Transcript Vol. VI, pp. 865-866].

82. The Department identifies a custody transfer meter as one where there is a transfer of custody for purposes of sale or similar disposition, rather than a location at which production volumes are measured. [Transcript Vol. VII, pp. 892-894]. The Department classifies the meters measuring volume at the wellhead as allocation meters, not custody transfer meters. [Transcript Vol. VII, p. 933].

83. ExxonMobil has historically referred to Black Canyon in company records, statements, communications and other project explanations as a “field dehydrator” or a “dehydration facility.” In its original 1985 “project plant,” ExxonMobil described a “Field Dehydration Facility” to be located at Black Canyon. [Exhibit 818, pp. 10215-10223]. It submitted large volumes of technical information in support of its request for various federal and state permits. This documentation consistently referred to Black Canyon as a “dehydration site” or “dehydration facility” or “field dehydration facility.” ExxonMobil also differentiated between the “Black Canyon Dehydrator” and the “Shute Creek Plant.” [Exhibit 107, pp. 15375, 15399, 15402, 15431, 15466-15473, 15544]. ExxonMobil also sought waiver of permitting requirements for construction of the “phase I dehydration plant in Sublette County, Wyoming.” [Exhibit 115, pp. 13629-13651].

84. MacFarland testified Black Canyon is still commonly referred to by company employees as a dehydration facility since that is part of what it does. He was not aware of any official directive to call it anything in particular. [Transcript Vol. IV, pp. 262-264].

85. Shute Creek is approximately 40 miles downstream from Black Canyon. The forty-mile pipeline between Black Canyon and the Shute Creek has thick walls designed to last for the life of the Shute Creek plant. The pipeline is equipped with eleven automatic block valves which can isolate portions of the pipeline to limit public exposure to hydrogen sulfide in the event of a leak. The inlet pressure of the pipeline is 1300 psi. The outlet pressure is 1050 psi. The temperature of the gas drops from 125°F to 90°F between Black Canyon and Shute Creek. [Joint Stipulation of Facts, ¶ 12; Transcript Vol. III, pp. 86-87, 143-145; Exhibit 106, pp. 16008-16012].

86. Construction on the Shute Creek plant commenced in May, 1984. [Joint Stipulation of Facts, ¶ 8]. Shute Creek is designed to have an unusually long life with extra thick walls in its vessels, equipment, and piping. In some instances, exotic materials were used to guard against long-term corrosion. While the original design life of the plant was fifty years, the current stated plant life is sixty years. There has been internal discussion of extending the stated plant life to seventy years. [Joint Stipulation of Facts, ¶ 6].

87. When construction was complete, the LaBarge project facilities comprised four main elements: a gathering and separating system; Black Canyon; a pipeline from Black Canyon to Shute Creek; and Shute Creek. Shute Creek began processing gas from the well fields in August, 1986. [Joint Stipulation of Facts, ¶ 9].

88. The Shute Creek plant, located in both Lincoln and Sweetwater Counties, covers approximately 500 acres, and contains two trains for gas processing. [Transcript Vol. III, p. 87; Exhibit 106, pp. 16013-16014].

89. When the raw gas stream reaches Shute Creek, it is rehydrated for processing to a moisture content of 0.07%. H₂S is then removed by Selexol through the process of absorption. The raw gas is stripped of H₂S, which is taken to sulfur recovery units where previously it has been converted into liquid molten sulfur, and transported by railcar to Opal. ExxonMobil has recently developed a sulfur disposal project in which the sulfur is now injected back into the earth. [Transcript Vol. III, pp. 147-148, 151-152, 163-165; Vol. IV, p. 282; Vol. V, pp. 622-623; Exhibit 106, pp. 16015, 16018-16020, 16124; Joint Stipulation of Facts, ¶ 13].

90. The refined hydrogen sulfide stream from the Selexol removal process feeds to a Sulfur Recovery Unit and a Tail Gas Cleanup Unit. The majority of sulfur is recovered in a furnace operating at 2000°F, fueled in part by burning a portion of the hydrogen sulfide. The plant generally achieves 99.9% sulfur recovery, which is slightly higher than required by its environmental permit. The small portion of unrecovered sulfur is incinerated which releases enough sulfur dioxide into the air to have affected the location of the Shute Creek plant. [Joint Stipulation of Facts, ¶ 16].

91. The Shute Creek plant next removes CO₂ from the gas stream. The CO₂ is removed in an absorber tower where Selexol rains down on the gas as it rises. CO₂ which can be sold is directed to compressors located three miles from the Shute Creek plant in Sweetwater County where it is compressed from a gaseous phase to a liquid at 2000 psi for pipeline delivery. It is then delivered by pipelines constructed by ExxonMobil to Chevron at Rock Springs for Chevron’s Rangely (Colorado) Field, and to Bairoil for Anadarko’s Salt Creek (Wyoming) Field. CO₂ which cannot be sold is vented. [Transcript Vol. III, pp. 95-97, 148-149, 153-159; Vol. IV, p. 281; Vol. VI, pp. 821, 823; Exhibit 106, p. 16015, 16028-16029, 16050, 16052-16060; Joint Stipulation of Facts, ¶¶ 14, 18].

92. After CO₂ processing, the gas stream still contains minute quantities of CO₂, as well as methane, nitrogen, water and helium. Water is removed in “mole sieve units.” The gas stream then enters the extremely cold nitrogen rejection process. [Transcript Vol. III, pp. 148-149].

93. The Nitrogen Rejection Unit, operating at -250°F to -300°F, separates the remaining gas into three streams. The first stream is half nitrogen and half helium, and feeds into the helium recovery plant. The second stream is methane. About five percent of this stream is compressed and sold as liquified natural gas (LNG). Although LNG is more valuable than methane, the plant design depends on revaporization of methane as a coolant, which reduces potential LNG production. The third stream is nitrogen, which is usually vented. Although the plant can produce liquid nitrogen, it cannot do so when the helium plant is operating at full capacity. [Transcript Vol. IV, p. 282; Joint Stipulation of Facts, ¶ 15].

94. Dr. Enick testified the Selexol solution used at Shute Creek is a good solvent not only for CO₂ and H₂S, but for DBTs and other HHCs as well which immediately dissolve into the Selexol solution. In his opinion, even if Black Canyon had not been built, the problems caused by the DBTs and other HHCs would have been encountered with the Selexol solution at Shute Creek. The Selexol solution would thus have required the same carbon filtration used at Black Canyon to clean the TEG solution. [Transcript Vol. V, pp. 565-566; Vol. VI, pp. 712-713].

95. The principal products of the raw gas stream available for sale are methane, liquefied natural gas, carbon dioxide, and helium. Methane gas is the most valuable product on the basis of total sales. [Joint Stipulation of Facts, ¶ 17].

96. The LaBarge project has the capability to process gas from three different federal production units: Lake Ridge, Graphite, and Fogarty Creek. ExxonMobil is the sole lessee of the federal leases in the Lake Ridge and Graphite Units. There are, however, other leaseholders in the Fogarty Creek Unit. ExxonMobil is the operator of all three units. ExxonMobil bore the costs of drilling in all three units with only original leaseholders Howell Petroleum Corporation and Yates Petroleum Corporation electing to share in the cost of drilling the Fogarty Creek unit. All other Fogarty Creek interest owners were non-consent. They did not participate in the cost of drilling the wells, and by contract cannot receive any proceeds from the wells until ExxonMobil, Howell, and Yates receive return of their investment in drilling costs, plus a penalty. The proportion at which ExxonMobil, Howell, and Yates carry the non-consent interests’ drilling costs varies from well to well. [Transcript Vol. VI, pp. 744-746; Joint Stipulation of Facts ¶ 22].

97. There are, in addition to the leaseholders in the three units, a number of private overriding royalty interests. Many Federal leases had been obtained by the original leaseholders through a lottery, and then resold to ExxonMobil and others. When resold, the original leaseholder commonly retained an interest in production from the lease. Payments of these overriding royalties are the responsibility of the leaseholder. Howell and Yates thus remained responsible for overriding royalties on production from their leases, and ExxonMobil remained responsible for overriding royalties on production from its leases. [Joint Stipulation of Facts, ¶ 23].

98. Construction of the Shute Creek plant created an independent set of ownership issues, most significantly with Howell and Yates. ExxonMobil refers to, and accounts for the Shute Creek plant cost as the cost of the entire infrastructure beyond the wellhead. By 1985, plant cost had doubled over original projections, and methane prices were falling. In this financial climate, ExxonMobil offered Howell and Yates a chance to acquire an ownership interest in the plant. Howell and Yates declined. [Joint Stipulation of Facts, ¶ 24].

99. Howell and Yates declined to become owners in the facilities to be constructed and installed downstream of the well heads. However, because their shares of the gas would have to be processed in the Shute Creek facility, ExxonMobil, Howell, and Yates attempted to negotiate an agreement for processing the Howell and Yates respective shares. Howell and Yates balked at the alternative of a straight processing fee agreement with ExxonMobil, because a fee based on ExxonMobil’s processing costs was too high, once depreciation and a return on investment were factored in. This impasse eventually prompted Howell and Yates to file an antitrust suit against ExxonMobil, seeking damages of $380 million. [Joint Stipulation of Facts, ¶ 25; Transcript Vol. VI, pp. 746-747].

100. The Howell and Yates litigation was ultimately resolved by negotiation of a complex processing agreement under which ExxonMobil agreed to process Howell’s and Yates’ respective shares of the natural gas production from the Fogarty Creek Unit. The processing agreements, known by the parties as the “Howell and Yates” Agreements, were entered into effective August 1, 1988. Under these Agreements, ExxonMobil agreed to process Howell’s and Yates’ respective shares of the raw gas for a fee initially equal to 65% of the gross revenues received from the sale of their shares of the production. [See 2004-84 Appeals at Findings of Fact ¶ 11 (citations to record omitted); Joint Stipulation of Facts, ¶ 26]. The same form of Agreement has been employed over the years to process gas owned by several other interest owners in the Fogarty Creek Unit, including Washington Energy and Foreman Enterprises. [Transcript Vol. VI, pp. 748-751; Exhibits 802, 803, 804, 805].

101. Since 1988, EOG Resources, Inc. has succeeded Howell Petroleum as a working interest owner at LaBarge. The Howell and Yates processing agreements still remain in effect. [Transcript Vol. VI, p. 751].

102. All facilities downstream of the wing valve on the well head are owned exclusively by ExxonMobil. These facilities include the gathering lines, manifolds, Black Canyon, the feed gas pipeline from Black Canyon to Shute Creek, and Shute Creek. All costs for facilities after the wing valve are incurred by ExxonMobil which is compensated for the costs of owning and operating these facilities for the benefit of other working interests owners by the terms of the Howell and Yates Agreements. [Transcript Vol. VI, pp. 747-748].

103. Article 7.1 of the Howell and Yates Agreements covers the gas owned by the separate working interest owners in the Fogarty Creek wells. The Article, by its terms, provides that possession, custody and control of Howell’s and Yates’ gas is transferred to ExxonMobil for processing immediately downstream of the wing valve on the wells, as measured by the metering stations located at each well site. [Transcript Vol. VI, pp. 751-755; Exhibit 805, pp. 51, 53, 54, 57, 58, 70].

104. Cindy Lee Gentry was ExxonMobil’s Operations Accounting Supervisor for the LaBarge operations team which succeeded the project’s construction team in the summer of 1986. She and her team were responsible for assuring that accounting systems existed to handle five operations issues: (1) cost accounting; (2) revenue accounting; (3) ownership; (4) state and federal royalties; and (5) severance and ad valorem taxes. [Joint Stipulation of Facts, ¶ 19].

105. Ms. Gentry read from Article 7.1 of the Howell and Yates Agreements, and summarized the provision as follows:

As [7.1] says, “The gas to be handled hereunder in this processing agreement shall be delivered to owner,” which in the definition is Exxon as operator of the LaBarge facilities, “at the facilities,” and that’s also defined, immediately downstream of the wing valve on the wellhead, and will be measured at the metering stations into the facilities at the flowing gas well pressure and temperature.

[Transcript Vol. VI, pp. 752, lines 5-12, 758; Exhibit 805, p. 57, Article 3.1 (definition of “facilities”)]. As a result, ExxonMobil takes custody of the raw gas at the wing valve and metering stations, but not title. Title remains with the working interest owner. [Transcript Vol. VI, pp. 752, 758]. Ms. Gentry described the purpose of this provision:

A. You have to define at what point they're [Howell and Yates] going to deliver it. And in our case, remembering this is two years after we started up, so we have already gone to the MMS -- before you start up, you have to go to the MMS and get your metering and allocation process approved. So we had already done that. So the metering station referred to here is, in fact, the metering station that we had gotten approved by the MMS. So we wanted to be very specific how we were going to measure the gas they're delivering to us and at exactly what point. And it all ties into the processing agreement in that we define the facilities that are covered by the processing fee and they start at the wing valve on the wellhead. So that's where Yates [and Howell] has to deliver their gas to us.

[Transcript Vol. VI, pp. 752, Lines 22-25, 753, Lines 1-12] (Clarification added).

106. Each of the Fogarty Creek unit wells have multiple working interest owners. Despite the fact that Fogarty Creek is unitized, each well has a slightly different working interest ownership because of parties who are “nonconsents,” and because the wells were originally drilled in an inconsistent manner under federal unit drilling blocks. ExxonMobil must account for each Fogarty Creek well separately to determine what percentage ownership in each well is attributable to ExxonMobil, and what percentage ownership in each well is attributable to one or more of the other working interest owners. The meters at the wells are used to measure this production transferred to ExxonMobil, and to properly account for the working interest and royalty ownership of the gas. [Transcript Vol. VI, pp. 753-757].

107. The metering requirement is not limited to Fogarty Creek. Although ExxonMobil owns the entire working interest in the Lake Ridge and Graphite units, it must meter each well individually since the gas from all three units is combined for processing through the LaBarge facilities. This means that measurements from each and every single well, through the meters located at each well, are necessary to properly account for the transfer of gas from Howell and Yates to ExxonMobil in the Fogarty Unit. The total production from the LaBarge field is allocated to the working interest owners based on each individual well. In order to properly calculate one working interest owner’s share of production in a Fogarty Creek well, ExxonMobil must know the amount of production from all wells. [Transcript Vol. VI, pp. 755-757].

108. In addition to the accounting and allocation issues between and among working interest owners, the BLM also requires individual meters at each well in all of the LaBarge units. [Transcript Vol. VI, p. 756].

109. After the gas is processed at Shute Creek, ExxonMobil markets all production and sends payments to the working interest owners reflecting the revenue from sale of their respective shares of product gas, net of the processing fee, as measured by the meters at the wells. [Transcript Vol. VI, pp. 762-771; Exhibit 101 at ¶ 12 (Findings of Fact, Conclusions of Law, and Order, Docket. Nos. 2004-84, 2004-85, 2004-120, 2004-140, December 1, 2005); Joint Stipulation of Facts ¶ 27; Exhibit 161].

110. ExxonMobil incurs post-plant transportation costs to deliver CO₂, methane, and sulfur to a point of sale. [Transcript Vol. I, pp. 91-92; Vol. VI, pp. 805-806, 809-813, 815-817, 820, 826-832].

111. ExxonMobil incurs post-plant transportation costs in the following eight categories:

∙ Railroad Spur and locomotive equipment to deliver sulfur from the plant to a main rail line near Opal

∙ CO₂ Compressors to compress the CO₂ to liquid form and move it to markets at Bairoil and Rangely

[Transcript Vol. I, pp. 90-92, 106-110, 113, 115-116; Vol. VI, pp. 773-777, 805-806, 809-813, 815-817, 820, 826-832; Confidential Exhibit 105].

112. ExxonMobil provided, on a confidential basis, the expense for each of the eight transportation cost categories. [Confidential Exhibit 105].

113. ExxonMobil, in reporting its 2005 taxable value, reported all post-plant transportation as direct transportation costs, and included those costs in its calculation of the direct cost ratio in the proportionate profits valuation methodology. [Transcript Vol. I, p. 69]. Those costs included facilities depreciation. [Transcript Vol. VI, pp. 792-794; Confidential Exhibit 105]. In calculating post-plant transportation, ExxonMobil reported using Mineral Management Service guidelines, and did not distinguish between direct and indirect costs. [Transcript Vol. VI, pp. 794-795].

114. Tuan Pham, on behalf of ExxonMobil, asserted the relevant Wyoming statutes and regulations do not address post-plant transportation, only “transportation costs.” Exxonmobil contends all transportation should be included in the direct cost ratio of the proportionate profits valuation methodology. Specifically, ExxonMobil contends the transportation costs incurred for the CO₂ pipeline to Bairoil should be included in the denominator of the direct cost ratio even though such expenses have nothing to do with processing transportation expenses. [Transcript Vol. I, pp. 93, 99, 101].

115. The post-plant transportation expenses which ExxonMobil asserts should be included in the direct cost ratio include direct supervision expenses, applicable property tax, and depreciation. [Transcript Vol. I, pp. 115-116].

116. The Department describes the movement of gas before the point of valuation as gathering, which is not deductible, and movement after the point of valuation as transportation, which is deductible. The post-plant transportation costs incurred after the point of valuation are deducted as a dollar-for-dollar deduction from the gross revenue received for the transported mineral at the point of sale. Those transportation costs are not included by the Department as direct costs in the proportionate profits methodology since they are specific to a mineral product, and thus do not need to be attributed by use of a ratio. [Transcript Vol. II, pp. 306-309, 340, 352; Vol. VI, pp. 839-840; Vol. VII, pp. 895-896, 961-962, 995-996; Exhibit 815, p.14026].

117. If the costs of post-plant transportation exceed the gross revenue received for a particular mineral, the Department reduces the value of that mineral to zero, rather than use a negative gross revenue number to create what would be a negative value for the mineral. [Transcript Vol. II, pp. 308-309; Vol. VII, p. 962].

118. The Department stresses that if post-plant transportation expenses are included in the direct cost ratio, those expenses are improperly allocated to all other minerals for both transportation and processing purposes, which is contrary to the purpose of the direct cost ratio. The Department asserts that including post-plant expenses in the direct cost ratio thus distorts and skews the application of the direct cost ratio in the proportionate profits valuation formula. If post-plant transportation costs for a specific mineral are included in the direct cost ratio, those costs for that specific mineral have the effect of lowering the value of all minerals produced at the plant tailgate. For example, including the post-plant transportation costs for CO₂ in the direct cost ratio has the effect of increasing the processing costs of methane. The value of methane is thus reduced by costs which are not associated with its production. [Transcript Vol. II, pp. 310-312, 351-352; Vol. VII, pp. 896-899, 961-962, 1003-1005].

119. The Department’s position is that if a producer-processor does not own or operate the post-plant transportation facilities, and pays a fee to a third party, the entire fee would be deducted from gross revenues. Because ExxonMobil owns the post-plant facilities, Grenvik asserts the Department is only permitted, by statute, to deduct direct costs. A deduction of, for example, return on investment, is not allowed. [Transcript Vol. II, pp. 348-351, 353].

120. The Department interprets the direct cost ratio of the proportionate profits valuation methodology to be a ratio of costs, including transportation costs, incurred from the wellhead downstream to the outlet of a processing facility – and not beyond. [Transcript Vol. II, pp. 311-312, 344, 347].

121. The function of the direct cost ratio in the proportionate profits valuation methodology, under the Department’s interpretation, is to allocate to the entire gas stream the expenses incurred to move the gas from the point of valuation to Shute Creek and to process the entire gas stream at that facility. The expenses incurred prior to the point of valuation are included in both the numerator and the denominator while the allowable costs incurred after the point of valuation are included only in the denominator. [Transcript Vol. VII, pp. 930-931, 960-961, 1003-1004].

122. The Department offered evidence to demonstrate the effect of including post-plant transportation expenses in the direct cost ratio. [Confidential Exhibits 500-501]. The Department showed that by including the post-plant transportation costs for CO₂ in the direct cost ratio, ExxonMobil reduced the overall taxable value of all minerals. Specifically, the Department showed that including the post-plant transportation costs for CO₂ in the direct cost ratio results in mineral values lower than if CO₂ was not valued and taxed at all. [Transcript Vol. II, pp. 369-371, 375-381; Confidential Exhibit 501].

It is only by either approving the determination of the Department, or by disapproving the determination and remanding the matter to the Department, that the issues brought before the Board for review can be resolved successfully without invading the statutory prerogatives of the Department.

Amoco Production Company v. Wyoming State Board of Equalization, 12 P.3d 668, 674 (Wyo. 2000). The Board’s duty is to adjudicate the dispute between taxpayers and the Department.

124. The Board is required to “[d]ecide all questions that may arise with reference to the construction of any statute affecting the assessment, levy and collection of taxes, in accordance with the rules, regulations, orders and instructions prescribed by the department.” Wyo. Stat. Ann. § 39-11-102.1(c)(iv).

125. “The burden of proof is on the party asserting an improper valuation.” Amoco Production Company v. Wyoming State Board of Equalization, 899 P.2d 855, 858 (Wyo. 1995); Teton Valley Ranch v. State Board of Equalization, 735 P.2d 107, 113 (Wyo. 1987); Britt v. Fremont County Assessor, 2006 WY 10, ¶ 17, 126 P.3d 117, 123 (Wyo. 2006); Thunder Basin Coal Company v. Campbell County, Wyoming Assessor, 2006 WY 44, ¶ 13, 132 P.3d 801, 806 (Wyo. 2006); Chevron U.S.A., Inc. v. Department of Revenue, State of Wyoming, 2007 WY 79, ¶ 30, 158 P.3d 131, 139(Wyo. 2007). The Board’s Rules provide:

[T]he Petitioner shall have the burden of going forward and the ultimate burden of persuasion, which burden shall be met by a preponderance of the evidence. If Petitioner provides sufficient evidence to suggest the Department determination is incorrect, the burden shifts to the Department to defend its action….

126. The Wyoming Supreme Court has summarized the procedure the Board must follow when an oil and gas taxpayer challenges the fair market value determined by the Department:

The Department’s valuations for state-assessed property are presumed valid, accurate, and correct. Chicago, Burlington & Quincy R.R. Co. v. Bruch, 400 P.2d 494, 498-99 (Wyo. 1965). This presumption can only be overcome by credible evidence to the contrary. Id. In the absence of evidence to the contrary, we presume that the officials charged with establishing value exercised honest judgment in accordance with the applicable rules, regulations, and other directives that have passed public scrutiny, either through legislative enactment or agency rule-making, or both. Id.

The petitioner has the initial burden to present sufficient credible evidence to overcome the presumption, and a mere difference of opinion as to value is not sufficient. Teton Valley Ranch v. State Board of Equalization, 735 P.2d 107, 113 (Wyo. 1987); Chicago, Burlington & Quincy R.R. Co., 400 P.2d 499. If the petitioner successfully overcomes the presumption, then the Board is required to equally weigh the evidence of all parties and measure it against the appropriate burden of proof. Basin [Electric Power Coop. Inc. v. Dep’t of Revenue, 970 P.2d 841,] at 851 [(Wyo. 1998)]. Once the presumption is successfully overcome, the burden of going forward shifts to the Department to defend its valuation. Id. The petitioner however, by challenging the valuation, bears the ultimate burden of persuasion to prove by a preponderance of the evidence that the valuation was not derived in accordance with the required constitutional and statutory requirements for valuing state-assessed property. Id.

Amoco Production Company v. Department of Revenue et al., 2004 WY 89, ¶¶ 7-8, 94 P.3d 430, 435-436 (Wyo. 2004). Accord, Airtouch Communications, Inc. v. Department of Revenue, State of Wyoming, 2003 WY 114, ¶ 12, 76 P.3d 342, 348 (Wyo. 2003); Colorado Interstate Gas Company v. Wyoming Department of Revenue, 2001 WY 34, ¶¶ 9-11, 20 P.3d 528, 531 (Wyo. 2001). The presumption the Department correctly performed the assessment rests in part on the complex nature of taxation. Airtouch Communications, Inc., supra, 2003 WY 114, ¶ 13, 76 P.3d at 348.

127. The uniformity of assessment requirement mandates only that the method of appraisal be consistently applied, recognizing there will be differences in valuation resulting from application of the same appraisal method:

The Board contends that reliance upon hypothetical costs is required because of the mandates for uniform assessment (Art. 15, § 11) and equal uniform taxation (Art. 1, § 28) found in the Constitution of the State of Wyoming. These provisions do not require, however, that all minerals of the like kind be assigned the same value. Uniformity of assessment requires only that the method of appraisal be consistently applied. Hillard v. Big Horn Coal Company, supra. It is an intrinsic fact in mineral valuation that differences in values result from the application of an appraisal method.

128. A taxpayer “aggrieved by any final administrative decision of the Department may appeal to the state board of equalization.” Wyo. Stat. Ann. § 39-14-209(b)(I). Oil and gas taxpayers are entitled to this remedy:

Following [the Department’s] determination of the fair market value of... natural gas production the department shall notify the taxpayer by mail of the assessed value. The person assessed may file written objections to the assessment with the state board of equalization within thirty (30) days of the date of postmark and appear before the board at a time specified by the board...

129. This appeal falls within a statute which does not establish any specific standard to guide the Board’s review. Wyo. Stat. Ann. § 39-14-209(b). In the absence of specific standards set by statute or rule, we judge the Department’s valuation by the general standard that the valuation must be in accordance with constitutional and statutory requirements for valuing state-assessed property. Amoco Production Company v. Department of Revenue et al., 2004 WY 89, ¶¶ 7-8, 94 P.3d 430; Wyo. Stat. Ann. § 39-14-209(b)(vi). In doing so, we must take into account “the rules, regulations, orders and instructions prescribed by the department.” Wyo. Stat. Ann. § 39-11-102.1(c)(iv). We also consider the case in the context of the Board Rule governing the burdens of going forward and of persuasion. Rules, Wyoming State Board of Equalization, Chapter 2, § 20. Chevron U.S.A., Inc., et al., Docket No. 2002-54 (January 25, 2005), 2005 WL 221595 (Wyo. St. Bd. Eq.).

130. “As we have often stated, our rules of statutory construction focus on discerning the legislature’s intent. In doing so, we begin by making an ‘inquiry respecting the ordinary and obvious meaning of the words employed according to their arrangement and connection.’ Parker Land and Cattle Company v. Wyoming Game and Fish Commission, 845 P.2d 1040, 1042 (Wyo.1993) (quoting Rasmussen v. Baker, 7 Wyo. 117, 133, 50 P. 819, 823 (1897)). We construe the statute as a whole, giving effect to every word, clause, and sentence, and we construe together all parts of the statute in pari materia. State Department of Revenue and Taxation v. Pacificorp, 872 P.2d 1163, 1166 (Wyo.1994).” Chevron U.S.A., Inc. v. Department of Revenue, 2007 WY 79, ¶ 15, 158 P.3d. 131, 136 (Wyo. 2007).

131. The Wyoming Supreme Court has previously summarized a number of useful precepts concerning statutory interpretation:

Statutes must be construed so that no portion is rendered meaningless. (citation omitted) Interpretation should not produce an absurd result. (citation omitted) We are guided by the full text of the statute, paying attention to its internal structure and the functional relation between the parts and the whole. (citations omitted) Each word of a statute is to be afforded meaning, with none to be rendered superfluous. (citation omitted) Further, the meaning afforded to a word should be that word’s standard popular meaning unless another meaning is clearly intended. (citation omitted) If the meaning of a word is unclear, it should be afforded the meaning that best accomplishes the statute’s purpose. (citation omitted) We presume that the legislature acts intentionally when it uses particular language in one statute, but not in another. (citations omitted) If two sections of legislation appear to conflict, they should be given a reading that gives them both effect. (citation omitted)

Rodriguez v. Casey, 2002 WY 111, ¶ 10, 50 P.3d 323, 326-327 (Wyo. 2002); quoted in Hede v. Gilstrap, 2005 WY 24, ¶ 6, 107 P.3d 158, 163 (Wyo. 2005).

132. “The omission of words from a statute must be considered intentional on the part of the legislature. (citation omitted) Words may not be supplied in a statute where the statute is intelligible without the addition of the alleged omission. (citations omitted) Words may not be inserted in a statutory provision under the guise of interpretation. (citations omitted) The Supreme Court will not read into laws what is not there. (citations omitted)” Matter of Adoption of Voss, 550 P.2d 481, 485 (Wyo. 1976).

133. “Determining the point of valuation is of particular significance because ‘expenses incurred by the producer prior to the point of valuation are not deductible in determining the fair market value of the [CBM].’ Wyo. Stat. Ann. § 39-14-203(b)(ii). Thus, because certain expenses ‘downstream’ of the point of valuation are deductible, it is to the producer’s benefit to have the point of valuation determined ‘upstream’ as far as possible. That is the instant case in a nutshell. Williams seeks an ‘upstream’ point of valuation instead of the ‘downstream’ point of valuation determined by the Department and confirmed by the Board.” Williams Production RMT Company v. Department of Revenue, 2005 WY 28, ¶ 10, 107 P.3d 179, 183-184 (Wyo. 2005)(Emphasis in original).

In addition to the observations of the DOA representative, the Board also relied upon a lengthy analysis whereby relevant statutory definitions and concepts were applied to Barrett’s system, and it also gave deference to the Department’s interpretation of a ‘processing facility’ because such was not in conflict with legislative intent. We find that the Board’s analysis, which is revealed in paragraphs 89-132 of the final order, that the TEG dehydrator was not located within a processing facility was a correct interpretation of the applicable statutes. Williams argues essentially that because the TEG dehydrator performs some of the functions listed in the definition of ‘processing’ contained in Wyo. Stat. Ann. § 39-14-201(a)(xviii), ipso facto, it too is a processing facility. When the statutes are read in para materia, as we are required to do, that reasoning simply does not fly. As the Board noted in Conclusion #122, Williams’ approach relies on a circular reading of the statute that is not supported by its plain language. The first sentence of the definition limits any activity deemed to be processing to those occurring ‘beyond the inlet to a natural gas processing facility.’ Wyo. Stat. Ann. § 39-14-201(a)(xviii). In addition, the definition recognizes that some of the functions specifically listed may occur during production. In reality, the definition of processing is of little assistance in determining what the legislature meant by processing facility in the context of the severance tax statutes.

Williams Production RMT Company v. Department of Revenue, 2005 WY 28, ¶ 17, 107 P.3d 179, 185 (Wyo. 2005).

135. This Board’s final order in Appeal of Williams Production RMT Company, Docket 2002-103, November 14, 2003, 2003 WL 22754175 (Wyo. St. Bd. Eq.), included the following paragraphs which are among those referenced in the preceding paragraph of the Wyoming Supreme Court’s Williams Production RMT Company decision:

89. The Wyoming Constitution requires the gross product of mines to be taxed in proportion to the value thereof and uniformly valued for tax purposes at full value as defined by the legislature. Wyo. Const. Art. 15, §§ 3, 11. For natural gas, the value of the gross product “means fair market value as prescribed by Wyo. Stat. Ann. 39-14-203(b), less any deduction and exemption allowed by Wyoming law or rules.” Wyo. Stat. Ann. §39-14-201(a)(xxix).

90. “The fair market value for...natural gas shall be determined after the production process is completed. ...[E]xpenses incurred by the producer prior to the point of valuation are not deductible in determining the fair market value of the mineral.” Wyo. Stat. Ann. §39-14-203(b)(ii). These two sentences contain two fundamental premises for our decision.

91. First, the point of valuation is a physical location. This physical location is determined by reference to the production process, and where that production process is completed. We will accordingly be deciding which party appropriately identified a point in the sequence of equipment that was the point of valuation.

92. Second, the point of valuation directly affects the calculation of expenses that may be deducted from Barrett’s sale price to determine fair market value. Barrett sold its gas at a location beyond the point of valuation. Findings of Fact, ¶19. For natural gas sold after the point of valuation, expenses incurred after the point of valuation are deducted from the sale price to reach fair market value. Wyo. Stat. Ann. §39-14-203(b)(vi). The taxpayer argues for a point of valuation that is closer to the wellhead, and further from the point of sale, than the point of valuation chosen by the Department of Revenue. If we found for the taxpayer, the effect would be to increase the deduction of expenses from the sale price of the taxpayer’s natural gas.

93. The statute determines the point of valuation for natural gas by reference to the production process:

The production process for natural gas is completed after extracting from the well, gathering, separating, injecting and any other activity which occurs before the outlet of the initial dehydrator. When no dehydration is performed, other than within a processing facility, the production process is completed at the inlet to the initial transportation related compressor, custody transfer meter or processing facility, whichever occurs first.

Wyo. Stat. Ann. §39-14-203(b)(iv)(hereafter, the point of valuation statute).

97. The point of valuation statute provides two possible avenues to determine when and where the production process is completed. Wyo. Stat. Ann. §39-14-203(b)(iv). The first avenue turns on the existence of an “initial dehydrator.”

99. On behalf of Williams, Rhinesmith directed our attention to three possible dehydrators: the header; the screw compressor; and the glycol dehydrator. Findings of Fact, ¶¶56-59. We will consider whether the statute enables us to determine whether one or more of these pieces of equipment is a dehydrator. We note that Williams’ Hearing Brief asserts that “dehydration occurs” at the header and “was performed” at the screw compressor. Petitioner’s Hearing Brief, pp. 8-9. We conclude the plain language of the first sentence of Wyo. Stat. Ann. §39-14-203(b)(iv) directs our attention to a “dehydrator,” not to dehydration.

100. The statute defines “dehydrator” as “a device which removes water vapor that is commonly associated with raw natural gas.” Wyo. Stat. Ann. § 39-14-201(a)(vii).

121. The statute does not define “processing facility.” The statute does define “processing:”

“Processing” means any activity occurring beyond the inlet to a natural gas processing facility that changes the well stream’s physical or chemical characteristics, enhances the marketability of the stream, or enhances the value of the separate components of the stream. Processing includes, but is not limited to fractionation, absorption, adsorption, flashing, refrigeration, cryogenics, sweetening, dehydration within a processing facility, beneficiation, stabilizing, compression (other than production compression such as reinjection, wellhead pressure regulation or the changing of pressures and temperatures in a reservoir) and separation which occurs within a processing facility.

Wyo. Stat. Ann. § 39-14-201(a)(xviii). This is a more complex definition than one would expect for the root word of “processing”, which is “process”. The common meaning of process is “a particular method of doing something, generally involving a number of steps or operations.” Webster’s New World College Dictionary (4^th Edition 2001) p. 1144.

122. The Williams position rests on the premise that the existence of a processing facility may be determined by reference to the functions described and listed in the definition of processing. Storts testified that he was the original source of this position. Findings of Fact, ¶30. The position was later elaborated in detail by Williams’ counsel in response to the preliminary audit findings. Findings of Fact, ¶¶38-39. The difficulty with the Williams position is that Williams depends upon a circular reading of the statute. We conclude that a circular reading is not supported by the plain language of the statute. Our conclusion is supported when we read the definition of “processing” in pari materia with other provisions of the statute, as we must. Fall v. State, id., at 983; Parker Land & Cattle Co. v. Game and Fish, id., at 1042.

123. Processing is “any activity occurring beyond the inlet to a natural gas processing facility...” “Natural gas”, is defined by statute. Wyo Stat. Ann §39-14-201(a)(x). In its briefs and argument, Williams has ignored this definition, which provides direct insight into the legislature’s intent, even though this definition was not enacted until 1998. 1998 Wyo. Sess. Laws, Ch. 5. The second sentence of the definition of natural gas states, “For the purposes of taxation, the term natural gas includes products separated for sale or distribution during processing the natural gas stream including, but not limited to plant condensate, natural gas liquids and sulfur.” Wyo. Stat. Ann. § 39-14-201(a)(xv)(emphasis supplied). This definition expresses at least some of the anticipated results of processing.

130. We also conclude that the Department’s interpretation does not conflict with legislative intent, and defer to the Department’s conclusion that Western’s booster compressor and glycol dehydrator are not a processing facility. Board of County Commissioners, Sublette County, v. State Board of Equalization, id., ¶16 ( Wyo. 2001).

136. The “value of the gross product,” for oil and gas, means fair market value as prescribed by Wyo. Stat. Ann. § 39-14-203(b), less any deductions and exemptions allowed by Wyoming law or rules. Wyo. Stat. Ann. § 39-14-201(a)(xxix).

(I) Crude oil, lease condensate and natural gas shall be valued for taxation as provided in this subsection;

(ii) The fair market value for crude oil, lease condensate and natural gas shall be determined after the production process is completed. Notwithstanding paragraph (x) of this subsection, expenses incurred by the producer prior to the point of valuation are not deductible in determining the fair market value of the mineral; * * *

(iv) The production process for natural gas is completed after extracting from the well, gathering, separating, injecting and any other activity which occurs before the outlet of the initial dehydrator. When no dehydration is performed, other than within a processing facility, the production process is completed at the inlet to the initial transportation related compressor, custody transfer meter or processing facility, whichever occurs first;

"Dehydrator" means a device which removes water vapor that is commonly associated with raw natural gas;

all gases, both hydrocarbon and nonhydrocarbon, that occur naturally beneath the earth's crust and are produced from an oil or gas well. For the purposes of taxation, the term natural gas includes products separated for sale or distribution during processing of the natural gas stream including, but not limited to plant condensate, natural gas liquids and sulfur;

141. The Wyoming Legislature “…has directed the Department to value natural gas production that is not sold at or prior to the point of valuation by bona-fide arms-length sale pursuant to one of four methods….” BP America Production Company v. Department of Revenue, 2005 WY 60, ¶ 5, 112 P.3d at 600. See also Chevron U.S.A., Inc. v. Department of Revenue, State of Wyoming, 2007 WY 79, ¶¶ 11, 12, 13, 158 P.3d 131, 134-136 (Wyo. 2007). The four methods are comparable sales, comparable value, netback, and proportionate profits. Id. The relevant method in this matter is proportionate profits:

(I) The total amount received from the sale of the minerals minus exempt royalties, nonexempt royalties and production taxes times the quotient of the direct cost of producing the minerals divided by the direct cost of producing, processing and transporting the minerals; plus

142. An understanding of the general operation of the proportionate profits methodology will be helpful in consideration of the point of valuation, and post-plant transportation issues in this matter. The proportionate profits methodology can be expressed graphically:

Fair Market Value

(Taxable Value)

equals

(=)

Total Sales Revenue

minus

(-)

Exempt Royalties

Non-exempt Royalties

Production Taxes

times

(x)

Direct Costs Ratio

plus

(+)

Nonexempt Royalties

Production Taxes

Direct Cost Ratio

equals

[=]

Direct Costs of Producing _________divided by______________

Direct Costs of Producing, Processing, & Transportation

RME Petroleum Co. v. Wyoming Dept. of Revenue, 2007 WY 16, ¶ 17, 150 P.3d 673, 681 (Wyo. 2007).

143. The calculation begins with the total revenue from sale of the processed natural gas in question.

144. From the total revenue, one subtracts two different kinds of royalties – exempt and non-exempt. Generally speaking, exempt royalties are paid to the United States, the State of Wyoming, or an Indian tribe. Rules, Wyoming Department of Revenue, Chapter 6 §4(o). Non-exempt royalties are paid to private individuals. Rules, Wyoming Department of Revenue, Chapter 6 §4(p). The difference is important because exempt royalties, once subtracted from total revenue at this stage, are not added back in the last step to determine taxable value. Exempt royalties, therefore, never become part of the taxable value of the mineral.

145. Production taxes are generally state severance and county ad valorem taxes on mineral production. Rules, Wyoming Department of Revenue, Chapter 6 §4(n). These taxes can only be calculated once the taxable value of the natural gas production is known. The proportionate profits method is therefore somewhat circular. To determine production taxes, we need to know taxable value. To determine taxable value, we need to know production taxes. While this is not an insurmountable problem, it is an inescapable feature of the proportionate profits method as enacted by the Legislature.

146. The revenue left after subtracting production taxes and royalties is further reduced when it is multiplied by a fraction. The numerator, or upper portion of the fraction, is equal to the direct costs of producing the mineral. There are two terms of art in the phrase “direct costs of producing.” One is direct costs as distinguished from indirect costs. The other is producing, which must be distinguished from processing and transportation.

147. The denominator, or lower portion of the fraction, is equal to the direct costs of producing plus the direct costs of processing and transporting the mineral. The statutory definition maintains the distinction between direct and indirect costs for the elements of the denominator.

148. ExxonMobil brought these consolidated appeals pursuant to Rules, Wyoming State Board of Equalization, Chapter 2 § 5. [Notices of Appeal]. We presume the appeals were also filed pursuant to Wyo. Stat. Ann. § 39-14-209(b)(i) under which “[a]ny person aggrieved by any final administrative decision of the department may appeal to the state board of equalization.” We thus judge the Department’s valuation decisions by the general standard that the valuation must be in accordance with constitutional and statutory requirements for valuing state-assessed property. Amoco Production Company v. Department of Revenue et al., 2004 WY 89, ¶¶ 7-8, 94 P.3d 430, 435-436; Wyo. Stat. Ann. § 39-14-209(b)(vi). The burden of going forward and the burden of ultimate persuasion rests with ExxonMobil. Rules, Wyoming State Board of Equalization, Chapter 2 § 20. Conclusions, ¶¶ 126, 129.

149. In applying this standard, the Board must presume the Department’s valuations are valid, accurate, and correct. BP America Production Company v. Department of Revenue, 2005 WY 60, ¶ 26, 112 P.3d 596, 608 (Wyo. 2005). ExxonMobil had the burden of presenting credible evidence to overcome the presumption. Id.; Chevron U.S.A., Inc. v. Department of Revenue, 2007 WY 79, ¶ 30, 158 P.3d 131, 139 (Wyo. 2007). A taxpayer’s burdens of proof and persuasion are further articulated in the Board’s Rules. Rules, Wyoming State Board of Equalization, Chapter 2 § 20. Conclusions, ¶¶ 126, 129.

150. These consolidated appeals present two distinct issues for resolution. The first addresses the proper point of valuation for natural gas production from the LaBarge Field. ExxonMobil asserts Black Canyon, which dehydrates the raw gas stream, is a gas processing facility, and therefore under Wyo. Stat. Ann. § 39-14-203(b)(iv), the point of valuation is what ExxonMobil terms as the joint custody meters at each well. The Department disagrees. It asserts Black Canyon is a dehydrator only, not a gas processing facility, thus the outlet or tailgate of Black Canyon is the proper point of valuation.

151. The second issue concerns the proper treatment of post-plant transportation expenses in the proportionate profits valuation methodology. ExxonMobil asserts such expenses must be included as a component of the proportionate profits direct cost ratio. The Department argues the post-plant transportation expenses for each product which is sold at a point beyond the tailgate of Shute Creek should be deducted from the gross sales revenue received for the specific product, with the resulting revenues net of such expenses to be used in the proportionate profits methodology.

152. We conclude the point of valuation for natural gas production from the LaBarge Field is the tailgate of Black Canyon; and the Department’s method for excluding post-plant transportation expenses from taxable value is correct.

153. Resolution of the point of valuation dispute between ExxonMobil and the Department rests primarily on whether Black Canyon is a “processing facility” under Wyo. Stat. Ann. § 39-14-203(b)(iv). Conclusions, ¶¶ 134, 137, 138.

154. The term “processing facility” is not defined by statute nor by the Department’s Rules. The statutes do, however, define “processing:”

any activity occurring beyond the inlet to a natural gas processing facility that changes the well stream's physical or chemical characteristics, enhances the marketability of the stream, or enhances the value of the separate components of the stream. Processing includes, but is not limited to fractionation, absorption, adsorption, flashing, refrigeration, cryogenics, sweetening, dehydration within a processing facility, beneficiation, stabilizing, compression (other than production compression such as reinjection, wellhead pressure regulation or the changing of pressures and temperatures in a reservoir) and separation which occurs within a processing facility;

155. The statutory definition of “natural gas” provides additional information about what constitutes a processing facility:

156. ExxonMobil characterizes the Board discussion in Williams with regard to what constitutes a processing facility as the Board initiating development of a “test” with four criteria as to what constitutes a processing facility:

In Williams, this Board identified four criteria that helped inform the analysis of what constitutes a processing facility:

A. Does the facility conform to the “common understanding” of what constitutes a processing facility? (Williams Board Opinion at ¶ 125);

B. Does the facility perform processing as that term is used in the statutory definition of “natural gas”? (Id.);

C. Does the facility perform the functions listed in the statutory definition of “processing”? (Id. at ¶131); and

D. Is the facility similar to Wyoming processing plants like Whitney Canyon, Painter, and Carter Creek, which were the type of processing facilities known to the Wyoming legislature when it passed the valuation statutes? (Id. at ¶¶ 125, 131).

[ExxonMobil Corporation’s Proposed Findings of Fact, Conclusions of Law ands Order, ¶¶ 132, 133].

157. ExxonMobil further argues this Board, in its Williams decision, applied a functional analysis in an attempt to determine whether a specific facility would be a processing facility:

The Board in Williams also applied a “functional” analysis to determine whether the specific facility in that case was a processing facility. Id. at ¶¶ 127, 129. In Williams, this Board found significant the fact that: 1) the glycol dehydrator removed impurities in such trivial amounts that they could be freely vented into the air without being subject to legal regulation; 2) coal bed methane is not a complex natural gas and contains few heavy hydrocarbons and impurities; and 3) in the absence of significant heavy hydrocarbons and impurities the process at issue would not yield significant amounts of natural gas liquids or sulfur. Id. at ¶ 127. . . .

[ExxonMobil Corporation’s Proposed Findings of Fact, Conclusions of Law ands Order, ¶ 134].

158. ExxonMobil then offers its conclusion that such a functional test assumes that if the converse of the circumstances cited by the Board in Williams, which concluded the facility in question was not a processing facility, are demonstrated to exist, then the facility is a processing facility:

…This functional test necessarily assumes that a converse set of circumstances would demonstrate the existence of a “processing facility,” i.e., a process facility is likely to exist when: 1) the glycol dehydration process yields non-trivial amounts of impurities that cannot be freely vented without legal regulation, thus requiring further treatment; 2) the natural gas at issue is complex and contains heavy hydrocarbons and substantial impurities; and 3) the process yields significant amounts heavy hydrocarbons and/or sulfur. All of those circumstances exist here, and thus the Black Canyon Facility is at the complete opposite end of the spectrum of functionality found relevant to this Board in Williams.

[ExxonMobil Corporation’s Proposed Findings of Fact, Conclusions of Law ands Order, ¶ 134].

159. ExxonMobil, based on its perception of what this Board stated in Williams, suggests the following four questions must be answered in the affirmative as pertain to Black Canyon, which is, therefore, a processing facility:

A. Is the facility a substantial facility? In other words, is the facility sufficiently large and complex in comparison to the types of facilities known to exist when the statutes were passed and which is clearly something more complicated than the kind of “off the shelf” dehydrators commonly employed at or near the well?

B. Does the facility remove non-trivial quantities of products from the raw gas stream, such that these products cannot just be vented but must instead become the subject of separate control and disposal processes?

C. Does the facility perform the functions listed in the statutory definition of “processing”? (For example, do the processes in the facility include “fractionation, absorption, adsorption, flashing, refrigeration, cryogenics, sweetening, dehydration within a processing facility, beneficiation, stabilizing, compression (other than production compression such as reinjection, wellhead pressure regulation or the changing of pressures and temperatures in a reservoir) and separation which occurs within a processing facility” Wyo. Stat. Ann. § 39-14-201(a)(xviii)).

D. Are the functions in the facility consistent with the processing functions included in the statutory definition of “natural gas,” Wyo. Stat. Ann. § 39-14-201(a)(xv)? Are products separated for sale or distribution in the facility?

[ExxonMobil Corporation’s Proposed Findings of Fact, Conclusions of Law ands Order, ¶¶ 139, 140].

160. These conclusions by ExxonMobil assume too much with regard to the Board’s discussions in Williams as to what should be considered in determining what constitutes a processing facility as specified in Wyo. Stat. Ann. § 39-14-203(b)(iv). In this appeal, as in Williams, the Board’s assigned responsibility is to review the evidence presented by ExxonMobil as compared to the conclusions by, and presumptions in favor of, the decisions by the Department, in light of the relevant statutes. We therefore decline ExxonMobil’s invitation to be guided by any criteria or functional analysis which it believes may be gleaned or deduced from our prior Williams decision. Conclusions, ¶¶ 126, 135.

161. There is no dispute Black Canyon fits the statutory definition of dehydrator since it functions as “a device which removes water vapor that is commonly associated with raw natural gas.” Wyo. Stat. Ann. § 39-14-201(a)(vii). Facts, ¶¶ 25, 30, 33, 67; Conclusions,¶ 139.

162. ExxonMobil presented copious evidence to support its assertion Black Canyon performs a significant number of the functions included within the statutory definition of processing. Wyo. Stat. Ann. § 39-14-201(a)(xviii);Conclusions, ¶ 138. Dr. Enick and others testified that Black Canyon performs absorption, adsorption, flashing, dehydration, beneficiation, stabilizing, compression, and separation. Facts, ¶¶ 34, 38, 46, 48, 61, 65, 66, 70, 71. ExxonMobil thus argues that one significant consideration in determining whether a facility is a processing facility is whether, and to what extent, the facility performs the statutorily designated processing functions. [ExxonMobil Corporation’s Proposed Findings of Fact, Conclusions of Law ands Order, ¶¶ 138, 139, 149].

163. This argument by ExxonMobil has been previously considered, in a slightly different situation, by the Board and the Wyoming Supreme Court in the Williams litigation. Conclusions, ¶ 135. Williams RMT had taken the position the existence of a processing facility could be determined, at least in part, by reference to the functions set forth in the statutory definition of processing. This Board found such reasoning to require a circular reading of the statutory definition of processing, a reading not supported by the plain language of the statute:

The difficulty with the Williams position is that Williams depends upon a circular reading of the statute. We conclude that a circular reading is not supported by the plain language of the statute. Our conclusion is supported when we read the definition of “processing” in pari materia with other provisions of the statute, as we must. Fall v. State, id., at 983; Parker Land & Cattle Co. v. Game and Fish, id., at 1042.

Williams Production RMT Co., Docket No. 2002-103 at ¶ 122, Nov. 14, 2003, 2003 WL 22754175 (Wyo. St. Bd. Eq.). Conclusions, ¶ 135.

Williams argues essentially that because the TEG dehydrator performs some of the functions listed in the definition of “processing” contained in Wyo. Stat. Ann. § 39-14-201(a)(xviii), ipso facto, it too is a processing facility. When the statutes are read in para materia, as we are required to do, that reasoning simply does not fly. As the Board noted in Conclusion # 122, Williams' approach relies on a circular reading of the statute that is not supported by its plain language. The first sentence of the definition limits any activity deemed to be processing to those occurring “beyond the inlet to a natural gas processing facility.” Wyo. Stat. Ann. § 39-14-201(a)(xviii). In addition, the definition recognizes that some of the functions specifically listed may occur during production.

Williams Production RMT Co. v. Wyoming Dept. of Revenue, 2005 WY 28, ¶ 17, 107 P.3d 179, 185 (Wyo. 2005).

165. We agree with the Supreme Court that “[i]n reality, the definition of processing is of little assistance in determining what the legislature meant by processing facility in the context of the severance tax statutes.” Williams Production RMT Co., 2005 WY 28, ¶ 17, 107 P.3d at 185. Conclusions, ¶ 134.

However, we can look, as the Board did, to the definition of “natural gas” for purposes of taxation for some insight into the legislative intent as to what was meant by “processing” in this context. Wyo. Stat. Ann. §39-14-201(a)(xv) provides that “[f]or the purposes of taxation, the term natural gas includes products separated for sale or distribution during processing of the natural gas stream including, but not limited to plant condensate, natural gas liquids and sulfur[.]”

Williams Production RMT Co., 2005 WY 28, ¶ 18, 107 P.3d at 185. Conclusions, ¶ 140.

167. We agree with the Supreme Court that this definitional language “implies that the legislature understood processing would separate certain products from the natural gas stream. Thus a processing plant logically would be a facility constructed to perform the function of removing such products. The TEG dehydrator would not constitute such a facility.” Williams Production RMT Co. 2005 WY 28, ¶ 18, 107 P.3d at 185.

168. ExxonMobil asserts Black Canyon does, in fact, actively separate products for sale or distribution under the natural gas definition of Wyo. Stat. Ann. § 39-14-201(a)(xv). [ExxonMobil Corporation’s Proposed Findings of Fact, Conclusions of Law ands Order, ¶¶ 151-157].

169. With regard to the requirement of distribution, ExxonMobil argues “[s]eparating, allocating and then dispensing of separated products is a ‘distribution’ of products from the raw gas stream.” [ExxonMobil Corporation’s Proposed Findings of Fact, Conclusions of Law ands Order, ¶ 154].

It is critical to recognize that ExxonMobil actually removes products for sale at Black Canyon. It is true that ExxonMobil removes DBTs, HHCs and elemental sulfur from the raw gas stream at Black Canyon. But it is equally true that ExxonMobil removes methane, carbon dioxide, helium and the other marketable components of the raw gas stream from the DBTs, HHCs and elemental sulfur at Black Canyon. The methane, carbon dioxide and helium are, of course, eventually sold. Methane could not be sold unless the DBTs and HHCs are first removed, because absent their removal the processes that render methane, CO₂ and helium would fail. Thus, the Black Canyon Facility actually causes the sale of methane, CO₂ and helium by the removal of heavy hydrocarbons that must be removed in order to permit a sale, which is no different than first removing H₂S before selling the methane. The order of removal cannot determine what is processing and what is not.

[ExxonMobil Corporation’s Proposed Findings of Fact, Conclusions of Law ands Order, ¶ 155].

171. The Department, in opposition, asserts that in order to have a processing facility, something more than dehydration must occur. A processing facility must produce a saleable product. The products which are separated must themselves be subject to “sale or distribution.” Facts, ¶ 74.

172. We believe the Department’s conclusions are more indicative of the Legislature’s intent with regard to what is a processing facility. The Legislature, in its definition of natural gas, intended to identify what products would be considered taxable natural gas, as the legislative definition itself states, “for purposes of taxation.” Wyo. Stat. Ann. § 39-14-201(a)(xv). The Legislature was clearly concerned with capturing, by definition, any and all valuable products which might be processed out of a natural gas stream and could be sold. It also anticipated the situation wherein a valuable product may not in fact be sold, but distributed to its owner without sale, thus the “distribution” language. It is entirely possible that an entity might be entitled to a separated product which the entity itself then utilizes without sale as a component of another product, or uses the separated product for fuel in the entity’s own plant or factory. Under such circumstances, the separate product as distributed would be considered, for purposes of taxation, “natural gas” and thus subject to valuation and taxation. Conclusions, ¶ 140.

173. The Department position that the products of a processing facility must, in effect, be marketable, and thus available for either sale or distribution, is an appropriate interpretation of the “natural gas processing facility” language of Wyo. Stat. Ann. § 39-14-201(a)(xviii), and finds support in the conclusion of the Wyoming Supreme Court that “a processing plant logically would be a facility constructed to perform the function of removing such products.” Williams Production RMT Co., supra, 2005 WY 28, ¶ 18, 107 P.3d at 185.

174. ExxonMobil’s assertion that it “removes methane, carbon dioxide, helium and the other marketable components of the raw gas stream from the DBTs, other HHCs and elemental sulfur at Black Canyon” ignores the syntax of the statutory language of Wyo. Stat. Ann. § 39-14-201(a)(xv). The language of the statute clearly focuses on what is removed by processing from the natural gas stream for sale or distribution, not the fact that some substances are separated from one another during a process which does not itself yield a product subject to taxation.

175. It is also, as the Wyoming Supreme Court noted, more logical to view a processing facility as a facility constructed to perform the function of removing from a natural gas stream products for sale or distribution, as occurs at Shute Creek, rather than to dehydrate raw gas in a facility which does not produce any valuable product such as Black Canyon. Conclusions, ¶ 167. In fact, the majority of the CO₂ and the H₂S removed at Black Canyon is injected back into the dehydrated gas stream for removal at Shute Creek. CO₂ is a marketable product, and H₂S, when processed, can produce a marketable product. Facts, ¶¶ 38, 39. The amounts of these gases which remain entrained in the water and water vapor, and are therefore injected with the water into disposal wells at Black Canyon, are not sold or distributed. Facts, ¶¶ 35, 36.

176. In addition, the raw gas passing through Black Canyon for dehydration must be rehydrated to ensure the proper functioning of the Selexol process at Shute Creek. Facts, ¶ 53. Such a condition simply underscores the conclusion that the principal function of Black Canyon is as a dehydrator to remove water from the raw gas stream in order to allow that stream to be safely transported to Shute Creek.

177. It is also interesting to note, although not of the major consequence subscribed to it by the Department, that ExxonMobil itself, as unquestionably a well-established and knowledgeable participant in the oil and gas industry, for many years referred to Black Canyon as a field dehydrator or a dehydration facility, not as a processing facility. While a rose by any other name is still a rose, thus a processing facility by any other name may still be a processing facility, the references by ExxonMobil to Black Canyon as a field dehydrator or a dehydration facility contradict its current position. Facts, ¶¶ 80, 83, 84; [Department of Revenue’s Proposed Findings of Fact and Conclusions of Law, ¶¶ 127-131].

178. ExxonMobil, through Dr. Enick and Steve MacFarland, presented copious testimony and exhibits in support of its assertion that Black Canyon is a gas processing facility. ExxonMobil argues that Black Canyon performs a number of functions defined by Wyo. Stat. Ann. § 39-14-201(a)(xviii) as processing. Dr. Enick also testified that based on his review of the technical chemical and petroleum engineering literature and texts, it was his opinion, from a technical, scientific, and engineering point of view, Black Canyon is a processing facility. Steve MacFarland, based on engineering parameters, definitions, and concepts, held the same opinion. Facts, ¶¶ 54, 55, 56, 67, 68, 70.

179. The overarching problem with this thoroughly presented evidence is the fact it is premised, as both Dr. Enick and Steve MacFarland testified, on a technical and scientific point of advocacy, not as an attempt to interpret the relevant Wyoming statutes. Dr. Enick in fact acknowledged he had not been asked to review the Wyoming statutes. He was asked by ExxonMobil to present a purely technical point of view with regard to Black Canyon. Facts, ¶ 54.

180. While the exhibits and testimony presented by Dr. Enick and Steve MacFarland might be appropriate if the question was how to characterize Black Canyon in a technical and engineering context, such evidence does not shed any particular light on, nor significantly assist in the task at hand, which is to determine the Wyoming Legislature’s intent in adopting Wyo. Stat. Ann. § 34-14-204(a)(iv), and use of the term “processing facility” therein.

181. ExxonMobil briefly argues in its post-hearing submission that because Black Canyon was expensive to build, Facts, ¶ 27; covers a large physical area; has significant facilities such as offices, a warehouse, maintenance garage, etc.; and is manned 24 hours everyday, Facts, ¶ 29, it thus “looks and acts like a processing facility.” [ExxonMobil Corporation’s Proposed Findings of Fact, Conclusions of Law ands Order, ¶¶ 142-144]. ExxonMobil, however, cites no legal authority, and thus gives this Board no legal basis in support of its argument that based on size and complexity, Black Canyon must be considered a processing facility. While Black Canyon may indeed be a large and complex facility, such characteristics do not prevent it from being a statutorily defined initial dehydrator. Wyo. Stat. Ann. §§ 39-14-203(b)(iv) & 39-14-201(a)(vii).

182. ExxonMobil further asserts that because the TEG dehydration process at Black Canyon removes what ExxonMobil chooses to characterize as “substantial amounts of contaminants from the raw gas stream,” such activity further indicates Black Canyon is a processing facility. ExxonMobil points to the fact that Black Canyon, through the TEG dehydration process, annually separates 5000 tons of H₂S, 17,000 tons of CO₂, and 78 tons of DBTs, other HHCs, and elemental sulfur. Facts, ¶ 36; [ExxonMobil Corporation’s Proposed Findings of Fact, Conclusions of Law ands Order, ¶ 145]. Dr. Enick, however, estimated the 5000 tons of H₂S and 17,000 tons of CO₂ constituted only about one percent (1%) of the H₂S and CO₂ in the LaBarge raw gas stream. Facts, ¶ 36. ExxonMobil argues separation of these contaminants is, in effect, processing which qualifies Black Canyon as a processing facility.

183. This separation and removal argument is undercut by two factors. First, the contaminant removal occurs as a part of the primary function at Black Canyon, to wit, to dehydrate the raw gas stream before it is sent through a 40-mile pipeline for processing at Shute Creek. Facts, ¶¶ 25, 30, 33, 67. The TEG process, besides it main function of removing water and water vapor, also removes H₂S and CO₂ as well as DBTs, other HHCs, and elemental sulfur, some of which ExxonMobil was not aware were contained in the raw gas stream until after Black Canyon was placed in operation. Facts, ¶¶ 33, 34, 36, 40, 41. ExxonMobil did not begin a serious effort to remove these contaminants from the TEG in order to make the raw gas stream saleable at Black Canyon. It was instead concerned with removing, in particular, the DBTs and other HHCs to prevent them from passing through Black Canyon and down to Shute Creek. At Shute Creek, these contaminants could cause problems with the Selexol process which separated the raw gas stream into products for sale. Facts, ¶¶ 44, 45, 47, 48, 49, 50, 69.

184. The second factor which undercuts the argument that removal of “contaminants” at Black Canyon is processing is the fact only very trivial quantities of both H₂S and CO₂removed by the TEG dehydration process are not reinjected back into the raw gas stream as it leaves Black Canyon for final removal at Shute Creek. Facts, ¶¶ 36, 37. Of the 5000 tons of H₂S removed by the TEG, only nine (9) tons are entrained in the acidic water removed by the TEG, and injected into disposal wells at Black Canyon. Facts, ¶¶ 35, 36. If 5000 tons of H₂S equals one percent (1%) of the H₂S in the raw gas stream, Facts, ¶ 36, then the nine (9) tons injected at Black Canyon is an extremely minute amount, approximately 0.0018%, of the total H₂S in the raw gas stream. Similarly, only two (2) tons of the CO₂are entrained in the acidic water and injected into disposal wells at Black Canyon. Facts, ¶¶ 35, 36. If 17,000 tons of CO₂ equals only one percent (1%) of the CO₂ in the raw gas stream, Facts, ¶ 36, the two (2) tons injected at Black Canyon is almost an incalculably small percentage, 0.00012%, of the total CO₂ in the raw gas stream. The remainder of both the H₂S and CO₂ is recovered from the TEG and injected back into the gas stream headed to Shute Creek where both are permanently removed. Black Canyon thus, as a practical matter, in processing as much as 720 million standard cubic feet of gas per day, permanently removes only infinitesimally small amounts of H₂S and CO₂ which are the major sour components of the LaBarge raw gas stream. Facts, ¶ 15. Such activity is clearly not processing on a level necessary to qualify Black Canyon as a processing facility as referenced in Wyo. Stat. Ann. § 39-14-203(a)(iv). Conclusions, ¶ 137.

185. The separation and removal argument appears to be an attempt by ExxonMobil to somehow inject into the determination of what is a processing facility a philosophy that the quantity of products removed, even if not sold, should somehow be a consideration. Neither the Wyoming statutes nor the Department Rules nor any Wyoming Supreme Court decision dealing with mineral valuation issues indicates in any manner that the quantity of what a facility removes is at all a factor in determining or defining a processing facility. A chemical analysis of what is removed from a raw gas stream by a facility has no basis in statutes, Rules, or case law, and should not in any manner affect the mineral value determined for calculation of ad valorem and severance taxes.

186. Black Canyon is an initial dehydrator under Wyo. Stat. Ann. § 39-14-203(a)(iv), with the point of valuation at the outlet thereof, and not a processing facility in which dehydration also occurs. It is therefore not necessary to address the arguments by ExxonMobil with regard to the processing agreements and custody transfer meters.

187. This issue concerns the narrow question of how transportation costs incurred downstream of Shute Creek for each individual plant product are to be accounted for within the proportionate profits method of valuation.

188. The costs in question are incurred by ExxonMobil for delivery of individual plant products from the outlet of Shute Creek to the point of sale to market purchasers. ExxonMobil asserts the post-plant transportation costs, including pipeline costs, compression, railway expenses, and other expenses for its CO₂, methane, helium, and sulfur must be included in the direct cost ratio. Facts, ¶¶ 110, 111, 113, 114, 115. ExxonMobil and the Department agree that a deduction is appropriate for these post-plant transportation costs. The manner in which the deduction is applied is the source of disagreement.

189. ExxonMobil contends the post-plant transportation costs for all plant products should be included in the direct cost ratio. Facts, ¶¶ 114, 115, 116. The Department responds that a dollar-for-dollar deduction from the revenue received for each product for post-plant transportation expenses is required by statute and rule. The Department argues the direct cost ratio should include only costs incurred between the wellhead and the outlet of the processing facility. The Department asserts the direct cost ratio should thus include only those costs generally incurred to produce, transport, or process the cumulative gas stream, not the costs incurred to transport individual products from the outlet of Shute Creek to the point of sale. Facts, ¶¶ 116, 117, 120.

190. Under the approach proposed by ExxonMobil for deducting post-plant transportation costs, the direct cost ratio will decrease if the numerator of the ratio includes those transportation costs. Conclusions, ¶¶ 142, 146. As a result, the taxable value of all plant products will decrease proportionately as the post-plant transportation expenses of individual minerals are included in the direct cost ratio. Facts, ¶¶ 118, 121.

191. Under the Department’s methodology of allowing a dollar-for-dollar deduction of post-plant transportation expenses from the revenue of each individual mineral, those expenses impact only the taxable value of the individual minerals, not the collective natural gas product stream. Facts, ¶ 118.

192. The proportionate profits methodology set forth in Wyo. Stat. Ann. § 39-14-203(b)(vi)(D) does not define transportation costs:

193. The Wyoming Supreme Court has noted “the objective of the proportionate profits method of computation is to ascertain gross income from mining by applying the principle that each dollar of total costs paid or incurred to produce, sell and transport the first marketable product…earns the same percentage of profit.” Powder River Coal Co. v. Wyo. State Bd. of Equalization, 2002 WY 5, ¶ 8, 38 P.3d 423, 427 (Wyo. 2002). This concept is administered through a “direct cost ratio” of direct production costs divided by total production, transportation and processing costs. Wyo. Stat. Ann. § 39-14-203(b)(vi)(D).

194. The Board has, in previous years, addressed the issue of deduction of post-plant transportation costs on a dollar for dollar basis. The Board, in Amoco Prod. Co., Docket No. 96-216, September 24, 2001, 2001 WL 1150220 (Wyo. St. Bd. Eq.), examined the issue as it pertained to Amoco’s sulfur haul road and load out facility expenses. Id., ¶¶ 132-136. The Board held the direct cost ratio should include only those costs of production, transportation and processing incurred from the wellhead downstream to the inlet of processing plant. Id., ¶ 134. The Board determined the costs of the sulfur haul road and load out facility operations were deductible transportation expenses incurred downstream of the processing facility, and therefore were not to be included in the direct cost ratio. The costs were, instead, deductible from sale of the sulfur product. Id., ¶ 135.

195. Amoco appealed the Board’s affirmance of the Department’s disallowance of transportation related expenses to the Wyoming Supreme Court. Amoco Prod. Co. v. Dep’t of Revenue, 2004 WY 89, ¶ 2, 94 P.3d 430, 434 (Wyo. 2004). The Court, however, did not discuss this particular issue when it affirmed the Department’s audit assessment with the exception of inclusion of production taxes and royalties in the direct cost ratio of the proportionate profits methodology. Id., ¶¶ 54-55.

196. The post-plant transportation issue was again disputed in Amoco Prod. Co., Docket No. 2000-69, Nov. 19, 2002, 2002 WL 31769513 (Wyo. St. Bd. Eq.). The Board again held the sulfur haul road and facility costs were not transportation costs to be included in the direct cost ratio of the proportionate profits formula. Id., ¶ 130. This Board again agreed the post-plant transportation costs were deductible on a dollar-for-dollar basis from sulfur revenue. Id., ¶ 131.

197. The Department, in part, bases its allowance of a dollar-for-dollar deduction of post-plant transportation costs on its Rules:

“Direct costs of production, processing and transporting” includes the direct cost of producing determined under paragraph (w) of this section plus transportation and processing plant or facility labor whose primary purpose is transporting or processing crude oil, plant condensate, natural gas and other mineral products removed from the production stream; materials and supplies used for transporting and processing; depreciation expense for equipment used for transportation and processing; fuel, power and other utilities used for transportation and processing and maintenance of the transporting and processing plant or facilities; transportation from the point of valuation to the processing plant or facility to the extent included in the price and provided by the producer; ad valorem taxes on the transporting equipment and processing plant or facility; and any other direct costs incurred that are specifically attributable to the transporting or processing of mineral products contained in the production stream.

198. The Department argues this definition allows inclusion in the direct cost ratio of only those transportation costs associated with processing the cumulative or entire raw gas stream. Facts, ¶¶ 117, 118, 120, 121.

199. As noted by the Wyoming Supreme Court, the interpretation of rules, as with statutes, requires first consideration of the plain language of the rule, with deference to, in this matter, the Department’s construction of its own rule, provided such construction is not clearly erroneous or inconsistent with the plain meaning of the rule:

We interpret rules in the same manner as statutes, looking first to the plain- language. . . . .

We will defer to an administrative agency’s construction of its rules unless that construction is clearly erroneous or inconsistent with the plain meaning of the rules. Pinther v. Department of Admin. & Info., 866 P.2d 1300, 1302 (Wyo. 1994).

RME Petroleum v. Wyoming Department of Revenue, 2007 WY 16, ¶¶ 43-44, 150 P.3d 673 at 688-689.

200. We can perceive no reason, under this judicial standard, to disagree with the Department’s interpretation of its own Rule.

201. Under Wyoming law, the fair market value of natural gas production is determined at the point when the production process has been completed. Wyo. Stat. 39-2-208(a). The LaBarge raw gas stream, however, must undergo extensive processing in order to have marketable products. For this reason the amount received from the sale of the products from the raw gas stream reflects the value of those products after both production and processing. In order to determine the value of the products after production only, it is necessary to deduct from the total amount received from the sale an amount reflecting the value added to the products by processing. The purpose of the direct cost ratio in the proportionate profits methodology is to allocate “a portion of a taxpayer’s revenue to non-taxable functions, i.e. processing and transporting.” RME Petroleum Company v. Wyoming Department of Revenue, 2007 WY 16, ¶ 51, 150 P.3d 673, 691 (Wyo. 2007). When individual mineral products are separated through processing as defined by statute, the producer may incur post-plant costs for transporting that particular mineral product to the point of sale. Those costs do not proportionately enhance the value of the other mineral products. Post-plant transportation costs thus bear no relevance to the value added by processing, and, therefore, do not belong in the direct cost ratio. The post-plant transportation costs for the tailgate products of Shute Creek should not be included in the direct cost ratio. Facts, ¶¶ 116, 121.

202. The Board is also cognizant of the effect of including post-plant transportation costs in the direct cost ratio. A statute should not be interpreted “ in a manner that produces absurd results.” Chevron U.S.A., Inc. v. Dep’t of Revenue, 2007 WY 43, ¶ 18, 154 P.3d 331, 337 (Wyo. 2007).

203. The uncontradicted evidence indicates that inclusion of post-plant transportation costs in the direct cost ratio results in reduction of the taxable value of all mineral products even though the transportation costs were incurred for post-plant transportation of individual mineral products following processing. Facts, ¶ 118.

204. The evidence demonstrated, in particular, that by including the post-plant transportation costs for CO₂ in the direct cost ratio, those costs were allocated and attributed to all the other minerals as well even though ExxonMobil incurred those expenses only for post-plant CO₂ transportation. All other transportation expenses in the direct cost ratio were incurred to transport the collective gas stream from the point of valuation to Shute Creek. Facts, ¶¶ 118, 121.

205. The uncontested evidence also indicated that under certain circumstances, including post-plant transportation costs in the direct cost ratio would reduce taxable value to such an extent that not taxing the particular mineral at all would generate a higher taxable value for the remaining minerals. Under these circumstances, taxing a particular mineral would generate a net negative result based on how post-plant transportation expenses are treated in the direct cost ratio. The evidence demonstrated that by including ExxonMobil’s 2005 post-plant transportation costs for CO₂ in the direct cost ratio, a lower taxable value was generated for the remaining minerals than if the CO₂ had not been taxed at all. Facts, ¶ 122. This is an absurd result.

206. ExxonMobil, for the first time in its Proposed Findings of Fact, Conclusions of Law and Order filed with the Board following the June, 2007, hearing, alludes to “potential constitutional issues associated with failure to uniformly treat transportation costs as an exclusion from taxable value,” citing J. Ray McDermott v. Hudson, 370 P.2d 364 (Wyo. 1962). [ExxonMobil Corporation’s Proposed Findings of Fact, Conclusions of Law ands Order, ¶ 173].

207. ExxonMobil argues that because the Department allows other producers to deduct the full amount of the third-party post-plant transportation fees which they incur, Facts, ¶ 119, but does not include in the direct cost ratio of the proportionate profits methodology the post-plant transportation incurred by ExxonMobil, the theory underlying the proportionate profits methodology is violated. ExxonMobil further asserts this treatment by the Department results in non-uniform treatment of post-plant transportation expenses in contravention of the principles laid out in McDermott.

208. This argument by ExxonMobil is deficient for at least two reasons. First, it is premised on the assertion, for which ExxonMobil presented no evidence other than a single question of, and answer by, Grenvik, that the fee charged by third-party transporters would include a profit component as well as a return on investment. In fact, the question to which Grenvik responded did not even specifically address a return on investment:

Q. Okay. So where the producer processor does not own or operate the post-plant transportation and pays a third party for it, the Department allows all of those third party fees?

Q. And those fees would normally be expected to include the third party transporter fees, costs and profit?

[Transcript Vol. II, pp. 348-349]. The evidentiary record herein clearly does not provide the Board sufficient information on what a third-party transporter might include in its charges to even discuss, much less reach, any viable conclusion on the question of whether the Department’s protocol for allowing a deduction for post-plant transportation expenses is constitutionally non-uniform.

209. The second deficiency in the constitutional argument by ExxonMobil derives from its interpretation of the Wyoming Supreme Court conclusions in McDermott. The issue in McDermott was the denial of any post-production transportation expenses. McDermott produced oil from wells located in the Ash Creek field, but because of a lack of pipeline facilities in that field, trucked the oil production, at its own expense, 138 miles to the Salt Creek field, the point of sale. The State Board of Equalization valued all mineral production in 1956, 1957, 1958, and 1959, the production years at issue. The Board refused to allow the expenses for trucking the oil from Ash Creek to Salt Creek as a deduction in calculating taxable value of McDermott’s oil production. The Wyoming Supreme Court concluded it was unconstitutional discrimination to fail to allow McDermott any deduction from the posted field price the Board used to value the production of other producers who sold their production without incurring post-production transportation expense. J. Ray McDermott v. Hudson, 370 P.2d at 370. The error in McDermott was the fact no post-production allowance or deduction at all was allowed in determining a taxable value for the oil production at issue. The Department in this matter obviously does allow a deduction, although not in the manner preferred by ExxonMobil. The Department is thus in compliance with both the letter and spirit of McDermott. A mere difference of opinion as to how to calculate, and the amount of, a deduction for post-plant transportation does not raise a constitutional issue.

210. The allowance by the Department of a dollar-for-dollar deduction of post-plant transportation costs against each tailgate product’s specific revenue appropriately recognizes such costs are deductible transportation expenses. The Department’s application of the proportionate profits methodology thus properly recognizes that costs included in the direct cost ratio are incurred to produce, transport and process a cumulative gas stream, which costs do not, and should not, include the costs to transport individually separated products after completion of processing to the point of sale.

IT IS THEREFORE HEREBY ORDERED the Notice of Valuation, and the Notice of Valuation Change issued by the Department are affirmed subject to remand to the Department for the reasons noted herein to void the assessment of federal helium, and to correct the proportionate profits methodology calculations which it has agreed are erroneous.

Pursuant to Wyo. Stat. Ann. § 16-3-114 and Rule 12, Wyoming Rules of Appellate Procedure, any person aggrieved or adversely affected in fact by this decision may seek judicial review in the appropriate district court by filing a petition for review within 30 days of the date of this decision.